View Filing Data

^[2]

(73)

Reclassification to Net Income of gains and losses on cash flow hedges

^[3]

(212)

(169)

^[4]

138

147

Unrealized actuarial gains and losses on pension and other post-retirement benefit plans

^[5]

(73)

(89)

(12)

Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans

^[6]

Comprehensive Income Attributable to Non-Controlling Interests

^[7]

(70)

(91)

(151)

Other Comprehensive Loss

(20)

(171)

(408)

Comprehensive Income

1,452

1,539

985

164

Comprehensive Income Attributable to Controlling Interests

1,355

1,375

907

Preferred Share Dividends

Comprehensive Income Attributable to Common Shares

$ 1,300

$ 1,320

$ 862

[1]	(1) Net of income tax expense of $32 million in 2012 (2011 - $29 million recovery; 2010 - $65 million expense).
[2]	(2) Net of income tax expense of $15 million in 2012 (2011 - $28 million recovery; 2010 - $37 million expense).
[3]	(3) Net of income tax expense of $13 million in 2012 (2011 - $106 million recovery; 2010 - $82 million recovery).
[4]	(4) Net of income tax expense of $81 million in 2012 (2011 - $77 million expense; 2010 - $28 million expense).
[5]	(5) Net of income tax recovery of $ 31 million in 2012 (2011 - $30 million recovery; 2010 - $7 million recovery).
[6]	(6) Net of income tax expense of nil in 2012 (2011 - $3 million expense; 2010 - $3 million expense).
[7]	(7) Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, reclassification to Net Income of gains and losses on cash flow hedges, offset by change in gains and losses on cash flow hedges, net of income tax recovery of $23 million in 2012 (2011 - $3 million recovery; 2010 - $69 million recovery).

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Comprehensive Income/ (Loss), income tax recovery (expense)
Foreign currency translation gains and losses on investments in foreign operations, income tax expense (recovery)	$ 32	$ (29)	$ 65
Change in fair value of net investment hedges, income tax expense (recovery)	15	(28)	37
Change in fair value of cash flow hedges, income tax expense (recovery)	13	(106)	(82)
Reclassification to Net Income of gains and losses on cash flow hedges, income tax expense	81	77	28
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans, income tax recovery	(31)	(30)	(7)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans, income tax expense		3	3
Other Comprehensive Loss on equity investments, income tax recovery	$ (23)	$ (3)	$ (69)

Tax effect of the income statement impact of the reclassification adjustment of accumulated gain (loss) from derivative instruments designated and qualifying as the effective portion of cash flow hedges realized in net income. Also includes reclassification adjustments of an entity's share of an equity investee's deferred hedging gain (loss) realized in net income.

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

CONSOLIDATED STATEMENT OF CASH FLOWS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash Generated from Operations
Net income	$ 1,472	$ 1,710	$ 1,393
Depreciation and amortization	1,375	1,328	1,160
Deferred income taxes (Note 15)	285	365	526
Income from equity investments (Note 9)	(257)	(415)	(453)
Distributed earnings received from equity investments (Note 9)	376	393	446
Employee post-retirement benefits funding lower than/(in excess of) expense (Note 20)	9	(2)	(50)
Valuation provision for MGP (Note 10)			146
Other	24	72	(7)
Decrease/(increase) in operating working capital (Note 22)	287	235	(285)
Net cash provided by operations	3,571	3,686	2,876
Investing Activities
Capital expenditures (Note 4)	(2,595)	(2,513)	(4,376)
Equity investments	(652)	(633)	(597)
Acquisitions, net of cash acquired (Note 23)	(214)
Deferred amounts and other	205	92	(323)
Net cash used in investing activities	(3,256)	(3,054)	(5,296)
Financing Activities
Dividends on common and preferred shares (Notes 18 and 19)	(1,281)	(1,016)	(754)
Distributions paid to non-controlling interests	(135)	(131)	(112)
Notes payable issued/(repaid), net	449	(224)	472
Long-term debt issued, net of issue costs	1,491	1,622	2,371
Repayment of long-term debt	(980)	(1,272)	(494)
Common shares issued, net of issue costs	53	58	26
Preferred shares issued, net of issue costs			679
Partnership units issued, net of issue costs (Note 23)		321
Net cash (used in)/provided by financing activities	(403)	(642)	2,188
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(15)	4	(7)
Decrease in Cash and Cash Equivalents	(103)	(6)	(239)
Cash and Cash Equivalents Beginning of year	654	660	899
Cash and Cash Equivalents End of year	$ 551	$ 654	$ 660

CONSOLIDATED BALANCE SHEET - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 551	$ 654
Accounts receivable	1,052	1,094
Inventories	224	248
Other (Note 5)	997	1,114
Total Current Assets	2,824	3,110
Plant, Property and Equipment (Note 6)	33,713	32,467
Equity Investments (Note 9)	5,366	5,077
Goodwill (Note 7)	3,458	3,534
Regulatory Assets (Note 8)	1,629	1,684
Intangible and Other Assets (Note 10)	1,343	1,466
Total Assets	48,333	47,338
Current Liabilities
Notes payable (Note 11)	2,275	1,863
Accounts payable and other (Note 12)	2,344	2,359
Accrued interest	368	365
Current portion of long-term debt (Note 14)	894	935
Total Current Liabilities	5,881	5,522
Regulatory Liabilities (Note 8)	268	297
Other Long-Term Liabilities (Note 13)	882	929
Deferred Income Tax Liabilities (Note 15)	3,953	3,591
Long-Term Debt (Note 14)	18,019	17,724
Junior Subordinated Notes (Note 16)	994	1,016
Total Liabilities	29,997	29,079
EQUITY
Common shares, no par value (Note 18) Issued and outstanding: December 31, 2012 - 705 million shares December 31, 2011 - 704 million shares	12,069	12,011
Preferred shares (Note 19)	1,224	1,224
Additional paid-in capital	379	380
Retained earnings	4,687	4,628
Accumulated other comprehensive loss	(1,448)	(1,449)
Controlling interests	16,911	16,794
Non-controlling interests (Note 17)	1,425	1,465
Total Equity	18,336	18,259
Total Liabilities and Equity	48,333	47,338
Commitments, Contingencies and Guarantees (Note 24)

CONSOLIDATED BALANCE SHEET (Parenthetical) - shares shares in Millions	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED BALANCE SHEET
Common shares issued (in shares)	705	704
Common shares outstanding (in shares)	705	704

CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - CAD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Foreign currency translation gains and losses on investments in foreign operations

$ (1,449)

$ (1,243)

$ (872)

^[1]

(129)

137

(223)

^[2]

(73)

Reclassification to Net Income of gains and losses on cash flow hedges

^[3]

(212)

(169)

^[4]

138

147

Unrealized actuarial gains and losses on pension and other post-retirement benefit plans

^[5]

(73)

(89)

(12)

Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans

^[6]

^[7]

(70)

(91)

(151)

Currency Translation Adjustments

(1,448)

(1,449)

(1,243)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

(643)

(683)

(592)

Cash Flow Hedges and Other

(707)

(643)

(683)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

(281)

(194)

(40)

Pension and Other Post-retirement Plan Adjustments

(110)

(281)

(194)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

(525)

(366)

(240)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

(631)

(525)

(366)

Parent

Foreign currency translation gains and losses on investments in foreign operations

^[8]

(108)

113

(180)

^[9]

(73)

Reclassification to Net Income of gains and losses on cash flow hedges

^[10]

(213)

(165)

^[11],[12]

138

137

Unrealized actuarial gains and losses on pension and other post-retirement benefit plans

^[13]

(73)

(89)

(12)

Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans

^[14]

Parent | Currency Translation Adjustments

^[15]

(70)

(91)

(151)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

Foreign currency translation gains and losses on investments in foreign operations

^[8]

(108)

113

(180)

Parent | Cash Flow Hedges and Other

^[9]

(73)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

Reclassification to Net Income of gains and losses on cash flow hedges

^[10]

(213)

(165)

^[11],[12]

138

137

Parent | Pension and Other Post-retirement Plan Adjustments

^[15]

(15)

(11)

(32)

Increase (decrease) in accumulated other comprehensive income (loss) net of tax

Unrealized actuarial gains and losses on pension and other post-retirement benefit plans

^[13]

(73)

(89)

(12)

Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans

^[14]

DESCRIPTION OF TRANSCANADA'S BUSINESS

^[15]

$ (55)

$ (80)

$ (119)

[1]	(1) Net of income tax expense of $32 million in 2012 (2011 - $29 million recovery; 2010 - $65 million expense).
[2]	(2) Net of income tax expense of $15 million in 2012 (2011 - $28 million recovery; 2010 - $37 million expense).
[3]	(3) Net of income tax expense of $13 million in 2012 (2011 - $106 million recovery; 2010 - $82 million recovery).
[4]	(4) Net of income tax expense of $81 million in 2012 (2011 - $77 million expense; 2010 - $28 million expense).
[5]	(5) Net of income tax recovery of $ 31 million in 2012 (2011 - $30 million recovery; 2010 - $7 million recovery).
[6]	(6) Net of income tax expense of nil in 2012 (2011 - $3 million expense; 2010 - $3 million expense).
[7]	(7) Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, reclassification to Net Income of gains and losses on cash flow hedges, offset by change in gains and losses on cash flow hedges, net of income tax recovery of $23 million in 2012 (2011 - $3 million recovery; 2010 - $69 million recovery).
[8]	(8) Net of income tax expense of $32 million and non-controlling interest losses of $21 million in 2012 (2011 - $29 million recovery, $24 million gain; 2010 - $65 million expense, $43 million loss).
[9]	(9)Net of income tax expense of $15 million in 2012 (2011 - $28 million recovery; 2010 - $37 million expense).
[10]	Net of income tax expense of $13 million and non-controlling interest gains of nil in 2012 (2011 - $106 million recovery, $1 million gain; 2010 - $82 million recovery, $4 million loss).
[11]	Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net Income in the next 12 months are estimated to be $41 million ($24 million, net of tax). These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.
[12]	Net of income tax expense of $81 million and non-controlling interest gains of nil in 2012 (2011 - $77 million expense, $10 million gain; 2010 - $28 million expense, $10 million gain).
[13]	Net of income tax recovery of $31 million in 2012 (2011 - $30 million recovery; 2010 - $7 million recovery).
[14]	Net of income tax expense of nil in 2012 (2011 - $3 million expense; 2010 - $3 million expense).
[15]	Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, reclassification to Net Income of gains and losses on cash flow hedges, offset by change in gains and losses on cash flow hedges, net of income tax recovery of $23 million in 2012 (2011 - $3 million recovery; 2010 - $69 million recovery).

CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE (LOSS)/INCOME (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Comprehensive Income/(Loss) Attributable to Non-Controlling Interests
Foreign currency translation gains and losses on investments in foreign operations, income tax expense (recovery)	$ 32	$ (29)	$ 65
Foreign currency translation gains and losses on investments in foreign operations, non-controlling interest (gain) loss	21	(24)	43
Change in fair value of net investment hedges, income tax expense (recovery)	15	(28)	37
Change in fair value of cash flow hedges, income tax expense (recovery)	13	(106)	(82)
Change in fair value of cash flow hedges, non-controlling interest loss (gain)		(1)	4
Reclassification to Net Income of gains and losses on cash flow hedges, income tax expense	81	77	28
Reclassification to Net Income of gains and losses on cash flow hedges, non-controlling interest gain		10	10
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans, income tax recovery	(31)	(30)	(7)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans, income tax expense		3	3
Other Comprehensive Loss on equity investments, income tax recovery	(23)	(3)	(69)
Estimated losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net Income in next 12 months, before tax	41
Estimated losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months, net of tax	24
Parent
Other Comprehensive Income/(Loss) Attributable to Non-Controlling Interests
Foreign currency translation gains and losses on investments in foreign operations, income tax expense (recovery)	32	(29)	65
Change in fair value of net investment hedges, income tax expense (recovery)	15	(28)	37
Change in fair value of cash flow hedges, income tax expense (recovery)	13	(106)	(82)
Reclassification to Net Income of gains and losses on cash flow hedges, income tax expense	81	77	28
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans, income tax recovery	(31)	(30)	(7)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans, income tax expense		3	3
Other Comprehensive Loss on equity investments, income tax recovery	$ (23)	$ (3)	$ (69)

CONSOLIDATED STATEMENT OF EQUITY - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests	Equity Attributable to Non-Controlling Interests TC PipeLines, LP	Equity Attributable to Non-Controlling Interests Portland	Equity Attributable to Non-Controlling Interests TRANSCANADA PIPELINES LIMITED
Balance at Dec. 31, 2009			$ 11,338	$ 539	$ 346	$ 4,158	$ (872)	$ 1,174
Increase (decrease) in equity
Shares issued under dividend reinvestment plan (Note 18)	$ 378		378
Shares issued on exercise of stock options (Note 18)			29
Shares issued under public offering, net of issue costs				685
Issuance of stock options, net of exercises					3
Net income attributable to controlling interests	1,278					1,278
Common share dividends						(1,109)
Preferred share dividends						(45)
Other comprehensive income/(loss)	(408)						(371)
Net income attributable to non-controlling interests	115								$ 87	$ 6
Preferred share dividends											$ 22
Other comprehensive (loss)/ income attributable to non-controlling interests								(37)
Sale of TC PipeLines, LP units
Distributions declared to non-controlling interests								(112)
Foreign exchange and other								17
Balance at Dec. 31, 2010	17,514	$ 16,357	11,745	1,224	349	4,282	(1,243)	1,157
Increase (decrease) in equity
Shares issued under dividend reinvestment plan (Note 18)	202		202
Shares issued on exercise of stock options (Note 18)			64
Issuance of stock options, net of exercises					1
Dilution gain from TC PipeLines, LP units issued (Note 23)					30
Net income attributable to controlling interests	1,581					1,581
Common share dividends						(1,180)
Preferred share dividends						(55)
Other comprehensive income/(loss)	(171)						(206)
Net income attributable to non-controlling interests	129								101	6
Preferred share dividends											22
Other comprehensive (loss)/ income attributable to non-controlling interests								35
Sale of TC PipeLines, LP units
Proceeds, net of issue costs									321
Decrease in TransCanada's ownership									(50)
Distributions declared to non-controlling interests								(131)
Foreign exchange and other								4
Balance at Dec. 31, 2011	18,259	16,794	12,011	1,224	380	4,628	(1,449)	1,465
Increase (decrease) in equity
Shares issued on exercise of stock options (Note 18)			58
Issuance of stock options, net of exercises					(1)
Net income attributable to controlling interests	1,354					1,354
Common share dividends						(1,240)
Preferred share dividends						(55)
Other comprehensive income/(loss)	(20)						1
Net income attributable to non-controlling interests	118								$ 91	$ 5
Preferred share dividends											$ 22
Other comprehensive (loss)/ income attributable to non-controlling interests								(21)
Sale of TC PipeLines, LP units
Distributions declared to non-controlling interests								(135)
Foreign exchange and other								(2)
Balance at Dec. 31, 2012	$ 18,336	$ 16,911	$ 12,069	$ 1,224	$ 379	$ 4,687	$ (1,448)	$ 1,425

DESCRIPTION OF TRANSCANADA'S BUSINESS

12 Months Ended

Dec. 31, 2012

DESCRIPTION OF TRANSCANADA'S BUSINESS

1. DESCRIPTION OF TRANSCANADA'S BUSINESS

TransCanada Corporation (TransCanada or the Company) is a leading North American energy company which operates in three business segments, Natural Gas Pipelines, Oil Pipelines and Energy, each of which offers different products and services.

Natural Gas Pipelines
The Natural Gas Pipelines segment consists of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities. Through its Natural Gas Pipelines segment, TransCanada owns and operates:

•: a natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec (Canadian Mainline);
•: a natural gas transmission system in Alberta and northeastern British Columbia (B.C.) (Alberta System);
•: a natural gas transmission system extending from producing fields primarily located in Texas, Oklahoma, the Gulf of Mexico and Louisiana to markets primarily located in Wisconsin, Michigan, Illinois, Ohio and Indiana, and includes regulated natural gas storage facilities in Michigan (ANR);
•: a natural gas transmission system extending from central Alberta to the B.C./Idaho border and to the Saskatchewan/Montana border (Foothills);
•: natural gas transmission systems in Alberta that supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP);
•: a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale); and
•: a natural gas transmission system in Mexico extending from Manzanillo, Colima to Guadalajara, Jalisco (Guadalajara).

Through its Natural Gas Pipelines segment, TransCanada operates and has ownership interests in natural gas pipeline systems as follows:

•

a 53.6 per cent direct ownership interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in eastern Canada and the northeastern and midwestern United States (U.S.) (Great Lakes);

•

a 75 per cent direct ownership interest in a natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border (GTN);

•

a 75 per cent direct ownership interest in a natural gas transmission system extending from the Powder River Basin in Wyoming to Northern Border in North Dakota (Bison);

•

a 61.7 per cent interest in a natural gas transmission system that extends from a point near East Hereford, Québec, to the northeastern U.S. (Portland);

•

a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near the Québec/Ontario border and transports natural gas to markets in Québec and to the Portland system (TQM); and

•

a 33.3 per cent controlling interest in TC PipeLines, LP, which has the following ownership interests in pipelines operated by TransCanada:

•: a 46.4 per cent interest in Great Lakes, in which TransCanada has a combined 69 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 50 per cent interest in a natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest (Northern Border), in which TransCanada has a 16.7 per cent effective ownership interest through TC PipeLines, LP;
•: a 25 per cent interest in GTN, in which TransCanada has a combined 83.3 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 25 per cent interest in Bison, in which TransCanada has a combined 83.3 per cent effective ownership interest through TC PipeLines, LP and a direct interest described above;
•: a 100 per cent interest in a natural gas transmission system extending from Arizona to Baja California at the Mexico/California border (North Baja), in which TransCanada has a 33.3 per cent effective ownership interest through TC PipeLines, LP; and
•: a 100 per cent interest in a natural gas transmission system extending from Malin, Oregon, to Wadsworth, Nevada (Tuscarora), in which TransCanada has a 33.3 per cent effective ownership interest through TC PipeLines, LP.

TransCanada does not operate but has ownership interests in natural gas pipelines and natural gas marketing activities as follows:

•: a 44.5 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. (Iroquois);
•: a 46.5 per cent interest in a natural gas transmission system extending from Mariquita to Cali in Colombia (TransGas); and
•: a 30 per cent interest in a natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile (Gas Pacifico), and in an industrial natural gas marketing company based in Concepción (INNERGY).

TransCanada is currently constructing natural gas pipeline systems as follows:

•: an extension to the Tamazunchale pipeline, extending the natural gas transmission system from Tamazunchale, San Luis Potosi to El Sauz, Queretaro;
•: a natural gas transmission system that will transport natural gas from Chihuahua to Topolobampo, Mexico (Topolobampo); and
•: a natural gas transmission system that will transport natural gas from El Oro to Mazatlan, Mexico (Mazatlan).

TransCanada is currently developing the following natural gas pipeline systems:

•: the proposed Coastal GasLink project consists of a natural gas transmission system that will transport natural gas from the Montney gas-producing region near Dawson Creek, B.C. to a liquefied natural gas export facility near Kitimat, B.C.; and
•: the proposed Prince Rupert Gas Transmission Project consists of a pipeline to deliver natural gas from the Fort St. John area of B.C. to the proposed Pacific Northwest LNG facility at Port Edward near Prince Rupert, B.C.

Oil Pipelines
The Oil Pipelines segment consists of a wholly owned and operated crude oil pipeline system which connects Alberta crude oil supplies to U.S. refining markets in Illinois and Oklahoma (Keystone Pipeline System).

TransCanada is currently constructing oil pipeline infrastructure as follows:

•: a crude oil pipeline to connect the crude oil hub at Cushing, Oklahoma to the U.S. Gulf Coast refining market (Gulf Coast Project);
•: the Cushing Marketlink receipt facilities that will transport crude oil supply from the Permian Basin in western Texas to the U.S. Gulf Coast on facilities that form part of the Gulf Coast Project; and
•: a crude oil terminal to be located at Hardisty, Alberta (Keystone Hardisty Terminal) that will provide Western Canadian producers with new batch accumulation tankage and pipeline infrastructure and access to the Keystone Pipeline System.

TransCanada is currently developing oil pipeline infrastructure as follows:

•: a new 1,897 km (1,179 mile) crude oil pipeline from Hardisty, Alberta to Steele City, Nebraska (Keystone XL), subject to regulatory approval;
•: the Bakken Marketlink project that will transport crude oil supply from the Williston Basin in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL;
•: the proposed Northern Courier Pipeline, a 90 km (54 mile) pipeline system to service the Fort Hills mine site and transport bitumen and diluent between the Fort Hills mine site and the proposed Voyageur Upgrader, north of Fort McMurray, Alberta. The Company has been selected by the Fort Hills Energy Limited Partnership to design, build, own and operate the proposed pipeline; and
•: the Grand Rapids Pipeline in northern Alberta, which includes both crude oil and diluent lines to transport volumes approximately 500 km (300 mile) between the producing area northwest of Fort McMurray and the Edmonton/Heartland region. The Company has entered into a joint venture agreement with Phoenix Energy Holdings Limited to develop the pipeline.

Energy
The Energy segment primarily consists of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities. Through its Energy segment, the Company owns and operates:

•: a natural gas and oil-fired generating facility in Queens, New York, consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology (Ravenswood);
•: a natural gas-fired, combined-cycle power plant in Halton Hills, Ontario (Halton Hills);
•: hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro);
•: a natural gas-fired peaking facility located near Phoenix, Arizona (Coolidge);
•: a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power);
•: a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour);
•: natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;
•: a wind farm located in Kibby and Skinner townships in northwestern Franklin County, Maine (Kibby Wind);
•: a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview);
•: a waste-heat fuelled power plant and the Cancarb thermal carbon black facility in Medicine Hat, Alberta (Cancarb);
•: a natural gas storage facility near Edson, Alberta (Edson); and
•: an underground natural gas storage facility near Crossfield, Alberta (CrossAlta).

TransCanada does not operate but has ownership interests in power generation plants as follows:

•: a 48.9 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce A and Bruce B (collectively Bruce Power), respectively, located near Tiverton, Ontario;
•: a 62 per cent interest in the Baie-des-Sables, Anse-à-Valleau, Carleton, Montagne-Sèche and Gros-Morne wind farms in Gaspé, Québec (Cartier Wind); and
•: a 50 per cent interest in a natural gas-fired, combined-cycle plant in Toronto, Ontario (Portlands Energy).

TransCanada has long-term power purchase arrangements (PPA) in place for:

•: a 100 per cent interest in the Sheerness power facility near Hanna, Alberta, which has 756 megawatts (MW) of generating capacity;
•: a 100 per cent interest in the Sundance A power facilities near Wabamun, Alberta, which has 560 MW of generating capacity; and
•: a 50 per cent interest in ASTC Power Partnership, which has a PPA in place for 706 MW of generating capacity from the Sundance B power facilities near Wabamun, Alberta.

TransCanada is currently constructing a 900 MW natural gas-fired power plant at Ontario Power Generation's Lennox site in Greater Napanee, Ontario.

TransCanada also has agreed to purchase nine Ontario solar projects in 2013 and 2014 with a combined capacity of 86 MW.

ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2012

ACCOUNTING POLICIES

ACCOUNTING POLICIES

2. ACCOUNTING POLICIES

The Company's consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise indicated. Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook, have been adjusted as necessary to be compliant with the Company's policies under U.S. GAAP. The amounts adjusted at December 31, 2011 and December 31, 2010 in these consolidated financial statements are the same as those reported in Note 25 of TransCanada's 2011 audited Consolidated Financial Statements included in TransCanada's 2011 Annual Report.

Basis of Presentation
The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.

Use of Estimates and Judgements
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies summarized below.

Regulation
In Canada, regulated natural gas pipelines and oil pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, oil pipelines and regulated storage assets are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission of Mexico. The Company's Canadian and U.S. natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. RRA is not applicable to the Keystone Pipeline System and the Company's Mexican natural gas pipelines and, as a result, the regulators' decisions regarding operations and tolls on these pipelines generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Natural Gas and Oil Pipelines
Revenues from the Company's natural gas and oil pipelines, with the exception of Canadian natural gas pipelines which are subject to rate regulation, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or oil are made. The U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized when appropriate.

Revenues from Canadian natural gas pipelines subject to rate regulation are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include an appropriate return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are periodically subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received.

Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.

Energy

Power
Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note.

Natural Gas Storage
Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.

Cash and Cash Equivalents
The Company's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Inventories
Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment

Natural Gas Pipelines
Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, Property and Equipment and the equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines.

When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

Oil Pipelines
Plant, property and equipment for oil pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When oil pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

Energy
Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.

Corporate
Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Impairment of Long-Lived Assets
The Company reviews long-lived assets, such as plant, property and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

Acquisitions and Goodwill
The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition with limited exception. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If TransCanada concludes that it is not more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.

Power Purchase Arrangements
A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. The PPAs under which TransCanada buys power are accounted for as operating leases. The initial payments for these PPAs were recognized in Intangible and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.

Income Taxes
The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Asset Retirement Obligations
The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

Recorded ARO relates to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, oil pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.

Environmental Liabilities
The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Emission allowances or credits purchased for compliance are recorded on the Balance Sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.

Stock Options and Other Compensation Programs
TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period, with an offset to Additional Paid-In Capital. Upon exercise of stock options, amounts originally recorded against Additional Paid-In Capital are reclassified to Common Shares.

The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.

Employee Post-Retirement Benefits
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.

The DB Plans' assets are measured at fair value. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive Loss (AOCI) over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the average remaining service life of active employees.

Foreign Currency Transactions and Translation
Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the company or reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt has been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation.

Derivative Instruments and Hedging Activities
All derivative instruments are recorded on the balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions.

The Company applies hedge accounting to arrangements that qualify and are designated for hedge accounting treatment, which includes fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest Income and Other and Interest Expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net Income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation.

In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in Net Income in the period of change.

The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory Assets or Regulatory Liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.

Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in Net Income.

Long-Term Debt Transaction Costs
The Company records long-term debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.

Guarantees
Upon issuance, the Company records the fair value of certain guarantees entered into by the Company or partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Other Long-Term Liabilities.

ACCOUNTING CHANGES

12 Months Ended

Dec. 31, 2012

ACCOUNTING CHANGES

ACCOUNTING CHANGES

3. ACCOUNTING CHANGES

Changes in Accounting Policies for 2012

Fair Value Measurement
Effective January 1, 2012, the Company adopted the Accounting Standards Update (ASU) on fair value measurements as issued by the Financial Accounting Standards Board (FASB). Adoption of this ASU has resulted in an increase in the qualitative and quantitative disclosures regarding Level III measurements which have been included in Note 21.

Intangibles – Goodwill
Effective January 1, 2012, the Company adopted the ASU on testing goodwill for impairment as issued by the FASB. Adoption of this ASU has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Company is now permitted to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test. The adoption of this standard had no impact on reported values of goodwill.

Future Accounting Changes

Balance Sheet Offsetting/Netting
In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect, of netting arrangements on an entity's financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments that are offset in accordance with current U.S. GAAP. This guidance is effective for annual periods beginning on or after January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosure regarding financial instruments which are subject to offsetting as described in this amendment.

The entire disclosure for reporting accounting changes and error corrections. It includes the conveyance of information necessary for a user of the Company's financial information to understand all aspects and required disclosure information concerning all changes and error corrections reported in the Company's financial statements for the period.

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2012

SEGMENTED INFORMATION

SEGMENTED INFORMATION

4. SEGMENTED INFORMATION


year ended December 31, 2012 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total

Revenues	4,264		1,039		2,704		–		8,007
Income from equity investments	157		–		100		–		257
Plant operating costs and other	(1,365	)	(296	)	(819	)	(97	)	(2,577	)
Commodity purchases resold	–		–		(1,049	)	–		(1,049	)
Property taxes	(315	)	(45	)	(74	)	–		(434	)
Depreciation and amortization	(933	)	(145	)	(283	)	(14	)	(1,375	)

	1,808		553		579		(111	)	2,829

Interest expense									(976	)
Interest income and other									85

Income before income taxes									1,938
Income tax expense									(466	)

Net Income									1,472
Net Income Attributable to Non-Controlling Interests									(118	)

Net Income Attributable to Controlling Interests									1,354
Preferred Share Dividends									(55	)

Net Income Attributable to Common Shares									1,299


year ended December 31, 2011 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines¹		Energy		Corporate		Total

Revenues	4,244		827		2,768		–		7,839
Income from equity investments	159		–		256		–		415
Plant operating costs and other	(1,221	)	(209	)	(842	)	(86	)	(2,358	)
Commodity purchases resold	–		–		(991	)	–		(991	)
Property taxes	(307	)	(31	)	(72	)	–		(410	)
Depreciation and amortization	(923	)	(130	)	(261	)	(14	)	(1,328	)

	1,952		457		858		(100	)	3,167

Interest expense									(937	)
Interest income and other									55

Income before income taxes									2,285
Income tax expense									(575	)

Net Income									1,710
Net Income Attributable to Non-Controlling Interests									(129	)

Net Income Attributable to Controlling Interests									1,581
Preferred Share Dividends									(55	)

Net Income Attributable to Common Shares									1,526

1: Commencing in February 2011, TransCanada began recording earnings for the Keystone Pipeline System.


year ended December 31, 2010 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Revenues	4,122		–	2,730		–		6,852
Income from equity investments	153		–	300		–		453
Plant operating costs and other	(1,165	)	–	(805	)	(99	)	(2,069	)
Commodity purchases resold	–		–	(1,178	)	–		(1,178	)
Property taxes	(294	)	–	(71	)	–		(365	)
Depreciation and amortization	(913	)	–	(247	)	–		(1,160	)
Valuation provision	(146	)	–	–		–		(146	)

	1,757		–	729		(99	)	2,387

Interest expense								(701	)
Interest income and other								94

Income before income taxes								1,780
Income tax expense								(387	)

Net Income								1,393
Net Income Attributable to Non-Controlling Interests								(115	)

Net Income Attributable to Controlling Interests								1,278
Preferred Share Dividends								(45	)

Net Income Attributable to Common Shares								1,233

Total Assets


at December 31 (millions of Canadian dollars)	2012	2011

Natural Gas Pipelines	23,210	23,161
Oil Pipelines	10,485	9,440
Energy	13,157	13,269
Corporate	1,481	1,468

	48,333	47,338

Geographic Information


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Revenues¹
Canada – domestic	3,527	3,929	3,178
Canada – export	1,121	1,087	838
United States	3,252	2,752	2,796
Mexico	107	71	40

	8,007	7,839	6,852

1: Revenues are attributed based on the country in which the product or service originated.


at December 31 (millions of Canadian dollars)	2012	2011

Plant, Property and Equipment
Canada	18,054	17,552
United States	14,904	14,388
Mexico	755	527

	33,713	32,467

Capital Expenditures


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Natural Gas Pipelines	1,389	917	1,192
Oil Pipelines	1,145	1,204	2,696
Energy	24	384	473
Corporate	37	8	15

	2,595	2,513	4,376

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

PLANT, PROPERTY AND EQUIPMENT

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2012

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

5. OTHER CURRENT ASSETS


at December 31 (millions of Canadian dollars)	2012	2011

Fair value of derivative contracts (Note 21)	259	361
Deferred income tax assets (Note 15)	290	248
Regulatory assets (Note 8)	178	178
Other	270	327

	997	1,114

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2012

PLANT, PROPERTY AND EQUIPMENT

6. PLANT, PROPERTY AND EQUIPMENT


		2012			2011
at December 31 (millions of Canadian dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Natural Gas Pipelines¹
Canadian Mainline
	Pipeline	8,801	5,192	3,609	8,785	4,958	3,827
	Compression	3,370	1,880	1,490	3,362	1,765	1,597
	Metering and other	391	182	209	383	175	208

		12,562	7,254	5,308	12,530	6,898	5,632
	Under construction	163	–	163	28	–	28

		12,725	7,254	5,471	12,558	6,898	5,660

Alberta System
	Pipeline	7,214	3,221	3,993	6,701	3,062	3,639
	Compression	1,885	1,177	708	1,778	1,109	669
	Metering and other	958	420	538	931	409	522

		10,057	4,818	5,239	9,410	4,580	4,830
	Under construction	463	–	463	368	–	368

		10,520	4,818	5,702	9,778	4,580	5,198

ANR
	Pipeline	864	49	815	858	47	811
	Compression	514	72	442	510	72	438
	Metering and other	520	81	439	524	59	465

		1,898	202	1,696	1,892	178	1,714
	Under construction	63	–	63	20	–	20

		1,961	202	1,759	1,912	178	1,734

Other Natural Gas Pipelines
	GTN	1,565	411	1,154	1,589	370	1,219
	Great Lakes	1,544	750	794	1,577	741	836
	Foothills	1,634	1,062	572	1,630	1,005	625
	Mexico	536	59	477	547	39	508
	Other²	1,548	226	1,322	1,576	187	1,389

		6,827	2,508	4,319	6,919	2,342	4,577
	Under construction	297	–	297	33	–	33

		7,124	2,508	4,616	6,952	2,342	4,610

		32,330	14,782	17,548	31,200	13,998	17,202

Oil Pipelines
Keystone
	Pipeline	4,897	177	4,720	4,904	80	4,824
	Pumping equipment	1,560	75	1,485	1,502	38	1,464
	Tanks and other	372	23	349	548	15	533

		6,829	275	6,554	6,954	133	6,821
Under construction³		3,678	–	3,678	2,433	–	2,433

		10,507	275	10,232	9,387	133	9,254

Energy
Natural Gas – Ravenswood		1,799	290	1,509	1,799	220	1,579
Natural Gas – Other⁴		2,975	746	2,229	3,002	665	2,337
Hydro		634	106	528	620	90	530
Wind⁵		907	118	789	843	88	755
Natural Gas Storage⁶		677	83	594	454	78	376
Other		134	86	48	131	83	48

		7,126	1,429	5,697	6,849	1,224	5,625
Under construction – Other		136	–	136	308	–	308

		7,262	1,429	5,833	7,157	1,224	5,933

Corporate		154	54	100	129	51	78

		50,253	16,540	33,713	47,873	15,406	32,467

1: In 2012, the Company capitalized $32 million (2011 – $23 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.
2: Includes in service assets of Bison, Portland, North Baja, Tuscarora and Ventures LP. Bison went in service in January 2011.
3: Includes $2.0 billion and $1.5 billion for Keystone XL and the Gulf Coast Project, respectively, at December 31, 2012 (2011 – $1.5 billion and $0.9 billion, respectively). Keystone XL remains subject to regulatory approvals.
4: Includes facilities with long-term PPAs that are accounted for as operating leases, including Coolidge which went in service in May 2011. The cost and accumulated depreciation of these facilities
were $601 million and $55 million, respectively, at December 31, 2012 (2011 – $605 million and $34 million, respectively). Revenues of $73 million were recognized in 2012 (2011 – $53 million; 2010 – $15 million)
through the sale of electricity under the related PPAs.
5: Includes Cartier phase two of Gros-Morne effective November 2012, phase one of Gros-Morne effective November 2011, and Montagne-Sèche effective November 2011.
6: Includes acquisition in December 2012 of BP's 40 per cent interest in the assets of the Crossfield Gas Storage facility and BP's interest in CrossAlta Gas Storage & Services Ltd.

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

RATE-REGULATED BUSINESSES

GOODWILL

12 Months Ended

Dec. 31, 2012

GOODWILL

GOODWILL

7. GOODWILL

The Company has recorded the following goodwill on its acquisitions in the U.S.:


(millions of Canadian dollars)	Natural Gas Pipelines		Energy		Total

Balance at January 1, 2011	2,634		823		3,457
Foreign exchange rate changes	59		18		77

Balance at December 31, 2011	2,693		841		3,534
Foreign exchange rate changes	(58	)	(18	)	(76	)

Balance at December 31, 2012	2,635		823		3,458

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2012

RATE-REGULATED BUSINESSES

8. RATE-REGULATED BUSINESSES

TransCanada's businesses that apply RRA currently include Canadian and U.S. natural gas pipelines and regulated U.S. natural gas storage. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations
The Canadian Mainline, Alberta System, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

TransCanada's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenues for the upcoming year. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur.

Canadian Mainline
In 2011, TransCanada filed a comprehensive application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline, including addressing tolls for 2012 and 2013. The application included a 7.0 per cent after-tax weighted average cost of capital (ATWACC) fair return which is equivalent to an ROE of 12 per cent on a deemed common equity of 40 per cent. This application is currently under review by the NEB with a decision not expected before late first quarter 2013 and accordingly, any adjustments relating to 2012 results will be recorded when the decision is received. In the absence of a decision by the NEB, Canadian Mainline's 2012 results reflect the last approved ROE of 8.08 per cent on a deemed common equity of 40 per cent and exclude incentive earnings.

The Canadian Mainline operated under a five-year settlement, effective from January 1, 2007 to December 31, 2011. The Canadian Mainline's cost of capital for establishing tolls under the settlement reflected an ROE as determined by the NEB's RH-2-94 ROE formula on a deemed common equity of 40 per cent. The allowed ROE in 2011 for the Canadian Mainline was 8.08 per cent. The balance of the capital structure was comprised of short and long-term debt.

The settlement also established the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. Variances in OM&A costs were shared equally between TransCanada and its customers in 2011. All other cost elements of the revenue requirement were treated on a flow-through basis. The settlement also allowed for performance-based incentive arrangements.

In September 2011, the NEB approved the Canadian Mainline's interim tolls as final for 2011, including TransCanada's proposal to carry forward any revenue variances into the determination of 2012 tolls. However, the NEB determined that TransCanada's inclusion of certain elements in the proposed 2011 revenue requirement, which were derived in accordance with the 2007-2011 Settlement, would be examined with TransCanada's 2012-2013 Tolls Application before a final decision was rendered on the 2011 revenue requirement. Any adjustments relating to the 2011 revenue requirement will be recorded when the NEB decision is received.

Alberta System
In September 2010, the NEB approved the Alberta System's 2010-2012 Revenue Requirement Settlement Application. The settlement provided for a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixed certain annual OM&A costs during the term. Any variances between actual costs and those agreed to in the settlement accrued to TransCanada. All other costs were treated on a flow-through basis.

Foothills
In June 2010, TransCanada reached an agreement to establish a cost of capital for Foothills that reflected a 9.70 per cent ROE on a deemed common equity of 40 per cent for 2010 to 2012. A component of OM&A was fixed, subject to the terms of the B.C. System/Foothills Integration Settlement, and variances between actual and fixed amounts were shared with customers up to and including June 2011 when the OM&A savings cap was reached.

TQM
In November 2010, the NEB approved TQM's multi-year settlement with its interested parties regarding its annual revenue requirements for 2010 to 2012. As part of the settlement, the annual revenue requirement was comprised of fixed and flow-through components. The fixed component included certain OM&A costs, return on rate base, depreciation and municipal taxes. Any variances between actual costs and those included in the fixed component accrued to TQM.

U.S. Regulated Operations
TransCanada's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR
ANR's natural gas transportation and storage services are provided for under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective beginning in 1997. ANR Pipeline Company is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if necessary. ANR Storage Company, which is another FERC regulated entity that owns and operates storage fields in Michigan, has rates that were established pursuant to a settlement approved by the FERC in August 2012. ANR Storage Company is required to file a NGA Section 4 general rate case no later than July 1, 2016.

In 2011, ANR Pipeline Company filed an application with the FERC to sell its offshore Gulf of Mexico assets and certain related onshore facilities to its wholly owned subsidiary, TC Offshore LLC. At the same time, TC Offshore LLC requested authorization from the FERC to acquire, own and operate those facilities under FERC regulation. The requests were granted and TC Offshore LLC began operating under FERC approved tariff rates on November 1, 2012. TC Offshore LLC is required to file a cost and revenue study to justify its existing approved cost-based rates after its first three years of operation.

GTN
GTN is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's rates were established pursuant to a settlement approved by the FERC in January 2012. That settlement provided for a four year moratorium during which GTN and the settling parties are prohibited from taking certain actions under the NGA, including filings to adjust rates. GTN is required to file for new rates to be effective January 1, 2016.

Great Lakes
Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. Great Lakes rates were established pursuant to a settlement approved by the FERC in July 2010. Great Lakes is required to file a NGA Section 4 general rate case no later than November 1, 2013.

Bison
Bison is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. Bison is permitted to discount or negotiate these rates on a non-discriminatory basis. Bison's rates were established pursuant to its initial certificate to construct and operate the pipeline that initiated service in January 2011.

Regulatory Assets and Liabilities


at December 31 (millions of Canadian dollars)	2012	2011	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	1,122	1,178	n/a
Operating and debt-service regulatory assets²	171	172	1
Adjustment account³	80	82	30
Other⁴	434	430	n/a

	1,807	1,862
Less: Current portion included in Other Current Assets	178	178

	1,629	1,684

Regulatory Liabilities
Foreign exchange on long-term debt⁵	150	184	1-17
Operating and debt-service regulatory liabilities²	84	135	1
Other⁴	134	117	n/a

	368	436
Less: Current portion included in Accounts Payable	100	139

	268	297

1: These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory
assets are not included in rate base and do not yield a return on investment during the recovery period.
2: Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in
determining tolls for the following calendar year. Pre-tax operating results in 2012 would have been $50 million lower (2011 – $102 million higher) had these amounts not been recorded
as regulatory assets and liabilities.
3: A regulatory adjustment account of $85 million was established and agreed upon by Canadian Mainline stakeholders to reduce tolls in 2010. Amortization of the adjustment account
commenced in 2011 at the composite depreciation rate.
4: Pre-tax operating results in 2012 would have been $97 million higher (2011 – $106 million lower) had these amounts not been recorded as regulatory assets and liabilities.
5: Foreign exchange on long-term debt of the Canadian Mainline, Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated
debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized
when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, U.S. GAAP would have
required the inclusion of these unrealized gains or losses in Net Income.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2012

EQUITY INVESTMENTS

EQUITY INVESTMENTS

9. EQUITY INVESTMENTS


		Income/(Loss) from Equity Investments				Equity Investments
	Ownership Interest as at	year ended December 31				at December 31
(millions of Canadian dollars)	December 31, 2012	2012		2011	2010	2012	2011

Natural Gas Pipelines
Northern Border¹		72		75	69	511	545
Iroquois	44.5%	41		40	40	174	181
TQM	50.0%	16		17	16	80	82
Other	Various	28		27	28	60	72
Energy
Bruce A	48.9%	(149	)	33	35	4,033	3,561
Bruce B	31.6%	163		77	138	69	115
ASTC Power Partnership	50.0%	40		84	41	42	58
Portlands Energy	50.0%	28		33	33	341	313
CrossAlta²		10		23	45	n/a	18
Other	Various	8		6	8	56	132

		257		415	453	5,366	5,077

1: The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2012, TransCanada had an ownership interest in TC PipeLines, LP of 33.3 per cent
(2011 – 33.3 per cent; 2010 – 38.2 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 16.7 per cent (2011 – 16.7 per cent; 2010 – 19.1 per cent).
2: In 2011, Property, Plant and Equipment included $63 million of assets owned directly by TransCanada through an undivided interest in the Crossfield joint venture which were utilized in the operations of the CrossAlta joint venture.
In December 2012, TransCanada acquired the remaining 40 per cent interest in CrossAlta to bring the Company's ownership interest to 100 per cent. The results reflect the Company's 60 per cent share of equity income up to
December 18, 2012. Refer to Note 23, Acquisitions and Dispositions, for additional information.

Distributions received from equity investments for the year ended December 31, 2012 were $436 million (2011 – $494 million; 2010 – $486 million) of which $60 million (2011 – $101 million; 2010 – $40 million) were returns of capital and are included in Deferred amounts and other in the Consolidated Statement of Cash Flows. The undistributed earnings from equity investments as at December 31, 2012 were $883 million (2011 – $1,062 million; 2010 – $1,141 million). At December 31, 2012, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company and Bruce Power is US$119 million (2011 – US$120 million) and $918 million (2011 – $820 million), respectively. This difference is primarily due to the fair value assessment of assets at the time of the acquisitions of Northern Border and Bruce Power, and interest capitalized related to the refurbishment of Units 1 and 2 at Bruce Power.

Summarized Financial Information of Equity Investments


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Income
Revenues	3,860		4,042		3,920
Operating and other expenses	(3,090	)	(2,989	)	(2,773	)
Net income	717		929		1,009
Net income attributable to TransCanada	257		415		453


at December 31 (millions of Canadian dollars)	2012		2011

Balance Sheet
Current assets	1,593		1,430
Non current assets	12,154		11,550
Current liabilities	(1,187	)	(1,172	)
Non current liabilities	(3,787	)	(3,232	)

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

INTANGIBLES AND OTHER ASSETS

INTANGIBLE AND OTHER ASSETS

12 Months Ended

Dec. 31, 2012

INTANGIBLES AND OTHER ASSETS

10. INTANGIBLE AND OTHER ASSETS


at December 31 (millions of Canadian dollars)	2012	2011

PPAs¹	376	428
Loans and advances²	196	224
Fair value of derivative contracts (Note 21)	187	202
Deferred income tax assets (Note 15)	105	132
Employee post-retirement benefits (Note 20)	11	–
Other	468	480

	1,343	1,466

1: The following amounts related to PPAs are included in Intangible and Other Assets:

2012

2011

at December 31
(millions of Canadian dollars)

Cost

Accumulated
Amortization

Net Book
Value

Cost

Accumulated
Amortization

Net Book
Value

Sheerness

585

273

312

585

234

351

Sundance A

225

161

225

148

810

434

376

810

382

428

Amortization expense for these PPAs was $52 million for the year ended December 31, 2012 (2011 and 2010 – $52 million). The expected annual amortization expense in each
of the next five years is $52 million.

2: As at December 31, 2012, TransCanada held a $236 million (2011 – $265 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and
matures in 2040. The current portion of the note receivable of $40 million (2011 – $41 million) is included in Other Current Assets.

Sundance A
In December 2010, Sundance A Units 1 and 2 were withdrawn from service and were subject to a force majeure claim by the PPA owner in January 2011. In July 2012, TransCanada received the binding arbitration decision regarding the Sundance A PPA force majeure and economic destruction claims. The arbitration panel determined that the PPA should not be terminated and ordered TransAlta Corporation (TransAlta) to return Units 1 and 2 to service. The panel also limited TransAlta's force majeure claim from November 20, 2011 until the units can reasonably be returned to service. TransAlta announced that it expects the units to be returned to service in fall 2013.

Between December 2010 and March 2012, TransCanada recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply. As a result of the decision, TransCanada recorded a $50 million pre-tax charge in second quarter of 2012, comprised of $20 million previously accrued in 2011 and $30 million previously accrued through first quarter of 2012, as these amounts are no longer recoverable. Other than the $20 million charge related to 2011 and the amortization of the original PPA cost, there are no pre-tax earnings recognized in 2012 for the Sundance A PPA.

Advances to Aboriginal Pipeline Group
The Mackenzie Delta gas producers, the Aboriginal Pipeline Group (APG) and TransCanada have an agreement governing TransCanada's role in the Mackenzie Gas Project (MGP). Under the agreement, TransCanada agreed to finance the APG for its one-third share of project pre-development costs. Amounts advanced to the APG for the MGP in 2012 and 2011 have been expensed. In 2010, a valuation provision of $146 million was recorded on the loan to the APG due to uncertainty with the project's ultimate commercial structure, fiscal framework, timeframes under which the project would proceed and when the advances to the APG will be repaid.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2012

NOTES PAYABLE

NOTES PAYABLE

11. NOTES PAYABLE


	2012		2011
(millions of Canadian dollars)	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31

Canadian dollars	803	1.2%	466	1.2%
U.S. dollars (2012 – US$1,480; 2011 – US$1,373)	1,472	0.4%	1,397	0.5%

	2,275		1,863

Notes payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada PipeLine USA Ltd. (TCPL USA) and TransCanada Keystone Pipeline, LP (TC Keystone) and drawings on line-of-credit and demand facilities.

At December 31, 2012, total committed revolving and demand credit facilities of $5.3 billion were available. When drawn, interest on the lines of credit is charged at prime rates of Canadian chartered and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

•: a $2.0 billion committed, syndicated, revolving, extendible TCPL credit facility, maturing October 2017. The facility was fully available at December 31, 2012. The cost to maintain the credit facility was $4 million in 2012 (2011 – $2 million; 2010 – $2 million);
•: a US$300 million committed, syndicated, revolving TCPL USA credit facility, guaranteed by TransCanada and maturing February 2013. At December 31, 2012, this facility was fully available. This facility is part of the initial US$1.0 billion credit facility discussed in Note 14. The cost to maintain the credit facility was nil in 2012 (2011 – $1 million; 2010 – $1 million);
•: a US$1.0 billion committed, syndicated, revolving, extendible TC Keystone credit facility, guaranteed by TCPL and TCPL USA and maturing November 2013. The facility was fully available at December 31, 2012. The cost to maintain the credit facility was $1 million in 2012 (2011 – $4 million; 2010 – $5 million);
•: a US$1.0 billion committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL and maturing October 2013. At December 31, 2012, this facility was fully available. The cost to maintain the credit facility was $1 million in 2012 (2011 – $4 million; 2010 – $4 million); and
•: demand lines totalling $1 billion, which support the issuance of letters of credit and provide additional liquidity. At December 31, 2012, the Company had used approximately $627 million of these demand lines for letters of credit.

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2012

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER

12. ACCOUNTS PAYABLE AND OTHER


at December 31 (millions of Canadian dollars)	2012	2011

Trade payables	923	696
Fair value of derivative contracts (Note 21)	283	485
Dividends payable	320	305
Regulatory liabilities (Note 8)	100	139
Deferred income tax liabilities (Note 15)	–	81
Other	718	653

	2,344	2,359

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2012

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES

13. OTHER LONG-TERM LIABILITIES


at December 31 (millions of Canadian dollars)	2012	2011

Employee post-retirement benefit (Note 20)	482	321
Fair value of derivative contracts (Note 21)	186	349
Guarantees (Note 24)	17	118
Asset retirement obligations	72	65
Other	125	76

	882	929

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2012

LONG-TERM DEBT

LONG-TERM DEBT

14. LONG-TERM DEBT


			2012		2011
Outstanding loan amounts (millions of Canadian dollars)		Maturity Dates	Outstanding December 31	Interest Rate¹	Outstanding December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
	Canadian dollars	2014 to 2020	874	10.9%	874	10.9%
	U.S. dollars (2012 – US$400; 2011 – US$600)	2021	398	9.9%	610	9.5%
Medium-Term Notes
	Canadian dollars	2013 to 2041	4,549	5.9%	4,549	5.9%
Senior Unsecured Notes
	U.S. dollars (2012 – US$10,126; 2011 – US$8,626)²	2013 to 2040	10,057	5.6%	8,759	6.2%

			15,878		14,792

NOVA GAS TRANSMISSION LTD.
Debentures and Notes
	Canadian dollars	2014 to 2024	382	11.5%	387	11.5%
	U.S. dollars (2012 – US$200; 2011 – US$375)	2023	199	7.9%	381	8.2%
Medium-Term Notes
	Canadian dollars	2025 to 2030	504	7.4%	504	7.4%
	U.S. dollars (2012 and 2011 – US$33)	2026	32	7.5%	33	7.5%

			1,117		1,305

TRANSCANADA PIPELINE USA LTD.
Bank Loan
	U.S. dollars (2012 – nil; 2011 – US$500)		–	–	509	0.6%

ANR PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$432)	2021 to 2025	430	8.9%	438	8.9%

GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$325)	2015 to 2035	323	5.5%	331	5.5%

TC PIPELINES, LP
Unsecured Loan
	U.S. dollars (2012 – US$312; 2011 – US$363)	2017	310	1.5%	369	1.6%
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$350)	2021	348	4.7%	356	4.7%

			658		725

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
	U.S. dollars (2012 – US$354; 2011 – US$373)	2018 to 2030	352	7.8%	379	7.8%

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
	U.S. dollars (2012 – US$27; 2011 – US$30)	2017	27	4.0%	31	4.4%

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes³
	U.S. dollars (2012 – US$129; 2011 – US$147)	2018	128	6.1%	149	6.1%

			18,913		18,659
Less: Current Portion of Long-Term Debt			894		935

			18,019		17,724

1: Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's regulated operations, in which case the weighted average interest rate is presented as
approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.
2: Includes fair value adjustments of $10 million (2011 – $13 million) attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$350 million of debt at December 31, 2012 (2011 – US$350 million).
3: Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments
Principal repayments on the long-term debt of the Company for the next five years are approximately as follows: 2013 – $894 million; 2014 – $970 million; 2015 – $1,561 million; 2016 – $1,214 million; and 2017 – $555 million.

TransCanada PipeLines Limited
In August 2012, TCPL issued US$1.0 billion of Senior Notes maturing August 1, 2022 and bearing interest at 2.5 per cent.

In May 2012, TCPL retired US$200 million of 8.625 per cent Senior Notes.

In March 2012, TCPL issued US$500 million of Senior Notes maturing March 2, 2015, and bearing interest at 0.875 per cent.

In November 2011, TCPL issued $500 million and $250 million of Medium-Term Notes maturing November 15, 2021 and November 15, 2041, respectively, and bearing interest at 3.65 per cent and 4.55 per cent, respectively.

In May 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes.

In January 2011, TCPL retired $300 million of 4.3 per cent Medium-Term Notes.

In September 2010, TCPL issued US$1.0 billion of Senior Notes maturing October 1, 2020, and bearing interest at 3.80 per cent.

In June 2010, TCPL issued US$500 million and US$750 million of Senior Notes maturing on June 1, 2015 and June 1, 2040, respectively, and bearing interest at 3.4 per cent and 6.1 per cent, respectively.

In February 2010, TCPL retired US$120 million of 6.125 per cent Medium-Term Notes and in August 2010, TCPL retired $130 million of 10.50 per cent debentures.

NOVA Gas Transmission Ltd.
In December 2012, NOVA Gas Transmission Ltd. (NGTL) retired US$175 million of 8.5 per cent Debentures.

Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made to December 31, 2012.

TransCanada PipeLine USA Ltd.
TCPL USA has an initial US$1.0 billion committed, unsecured, syndicated credit facility, guaranteed by TransCanada which was reduced to a US$300 million credit facility through term loan repayments of US$500 million and US$200 million in January 2012 and August 2011, respectively. The facility consists of a US$300 million revolving facility maturing in February 2013, described further in Note 11. The term loan's outstanding balance of US$500 million at December 31, 2011 was fully repaid in January 2012.

TC PipeLines, LP
In July 2011, TC PipeLines, LP increased its senior syndicated revolving credit facility to US$500 million and extended the maturity date to July 2016. In November 2012, the Senior Credit facility was further amended, extending the maturity date to November 2017.

In December 2011, TC PipeLines, LP repaid a maturing US$300 million term loan with a draw under this facility, and at December 31, 2012, US$312 million (2011 – US$363 million) was outstanding on the facility. In June 2011, TC PipeLines, LP issued US$350 million of 4.65 per cent Senior Notes due 2021. The proceeds from the issuance were used to partially repay TC PipeLines, LP's term loan and borrowings under its senior revolving credit facility, and repay its bridge loan facility described below.

In May 2011, TC PipeLines, LP made draws of US$61 million on a bridge loan facility and US$125 million on its senior revolving credit facility to partially fund the acquisition of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) as further described in Note 23.

Interest Expense


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Interest on long-term debt	1,190		1,154		1,149
Interest on junior subordinated notes	63		63		65
Interest on short-term debt	16		16		15
Capitalized interest	(300	)	(302	)	(587	)
Amortization and other financial charges¹	7		6		59

	976		937		701

1: Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes
in the fair value of derivatives used to manage the Company's exposure to rising interest rates.

The Company made interest payments of $966 million in 2012 (2011 – $926 million; 2010 – $652 million) on long-term debt and junior subordinated notes, net of interest capitalized on construction projects.

INCOME TAXES

12 Months Ended

Dec. 31, 2012

INCOME TAXES

INCOME TAXES

15. INCOME TAXES

Provision for Income Taxes


year ended December 31 (millions of Canadian dollars)	2012	2011		2010

Current
Canada	167	212		31
Foreign	14	(2	)	(170	)

	181	210		(139	)

Deferred
Canada	69	139		175
Foreign	216	226		351

	285	365		526

Income Tax Expense	466	575		387

Geographic Components of Income


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Canada	842	1,176	811
Foreign	1,096	1,109	969

Income before Income Taxes	1,938	2,285	1,780

Reconciliation of Income Tax Expense


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Income before Income Taxes	1,938		2,285		1,780
Federal and provincial statutory tax rate	25.0%		26.5%		28.0%
Expected income tax expense	485		605		498
Income tax differential related to regulated operations	41		42		8
Higher/(lower) effective foreign tax rates	1		(5	)	(36	)
Income from equity investments and non-controlling interests	(40	)	(45	)	(40	)
Other	(21	)	(22	)	(43	)

Actual Income Tax Expense	466		575		387

Deferred Income Tax Assets and Liabilities


at December 31 (millions of Canadian dollars)	2012	2011

Deferred Income Tax Assets
Operating loss carryforwards	1,024	900
Financial instruments	88	166
Pension and other post-employment benefits	83	42
Deferred amounts	49	49
Other	92	132

	1,336	1,289

Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	3,804	3,609
Equity investments	578	457
Taxes on future revenue requirement	283	295
Unrealized foreign exchange gains on long-term debt	159	133
Other	70	87

	4,894	4,581

Net Deferred Income Tax Liabilities	3,558	3,292

The above deferred tax amounts have been classified in the Consolidated Balance Sheet as follows:


at December 31 (millions of Canadian dollars)	2012	2011

Deferred Income Tax Assets
Other current assets (Note 5)	290	248
Intangible and other assets (Note 10)	105	132

	395	380

Deferred Income Tax Liabilities
Accounts payable and other (Note 12)	–	81
Deferred income taxes	3,953	3,591

	3,953	3,672

Net Deferred Income Tax Liabilities	3,558	3,292

At December 31, 2012, the Company has recognized the benefit of unused non-capital loss carryforwards of $865 million (2011 – $450 million) for federal and provincial purposes in Canada, which expire from 2014 to 2032.

At December 31, 2012, the Company has recognized the benefit of unused net operating loss carryforwards of US$2,174 million (2011 – US$2,119 million) for federal purposes in the U.S., which expire from 2028 to 2032.

Unremitted Earnings of Foreign Investments
Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2012 by approximately $144 million (2011 – $136 million) if there had been a provision for these taxes.

Income Tax Payments
Income tax payments of $190 million, net of refunds, were made in 2012 (2011 – refunds, net of payments made, of $84 million; 2010 – payments, net of refunds, of $53 million).

Reconciliation of Unrecognized Tax Benefit
Below is the reconciliation of the annual changes in the total unrecognized tax benefit:


at December 31 (millions of Canadian dollars)	2012		2011		2010

Unrecognized tax benefits at beginning of year	52		62		55
Gross increases – tax positions in prior years	2		9		7
Gross decreases – tax positions in prior years	(6	)	(7	)	(1	)
Gross increases – tax positions in current year	9		11		9
Settlements	–		–		(7	)
Lapses of statute of limitations	(8	)	(23	)	(1	)

Unrecognized tax benefits at end of year	49		52		62

TransCanada expects the enactment of certain Canadian federal tax legislation in the next 12 months which is expected to result in a favourable income tax adjustment of approximately $25 million. Otherwise, subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

TransCanada and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2007. Substantially all material U.S. federal income tax matters have been concluded for years through 2007 and U.S. state and local income tax matters through 2007.

TransCanada's practice is to recognize interest and penalties related to income tax uncertainties in Income Tax Expense. Net tax expense for the year ended December 31, 2012 reflects a reversal of $2 million of interest expense and nil for penalties (2011 – $12 million reversal of interest expense and nil for penalties; 2010 – $3 million for interest expense and nil for penalties). At December 31, 2012, the Company had $5 million accrued for interest expense and nil accrued for penalties (December 31, 2011 – $7 million accrued for interest expense and nil accrued for penalties).

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2012

JUNIOR SUBORDINATED NOTES

16. JUNIOR SUBORDINATED NOTES


			2012		2011
Outstanding loan amount (millions of Canadian dollars)		Maturity Date	Outstanding December 31	Effective Interest Rate	Outstanding December 31	Effective Interest Rate

TRANSCANADA PIPELINES LIMITED
	U.S. dollars (2012 and 2011 – US$1,000)	2067	994	6.5%	1,016	6.5%

Junior Subordinated Notes of US$1.0 billion mature in 2067 and bear interest at 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate plus 221 basis points. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. However, the Company would be prohibited from paying dividends during any such deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and other obligations of TCPL. The Junior Subordinated Notes are callable at the Company's option at any time on or after May 15, 2017, at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with the terms of the Junior Subordinated Notes.

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2012

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS

17. NON-CONTROLLING INTERESTS

The Company's non-controlling interests included in the Consolidated Balance Sheet were as follows:


at December 31 (millions of Canadian dollars)	2012	2011

Non-controlling interest in TC PipeLines, LP¹	953	997
Preferred shares of TCPL	389	389
Non-controlling interest in Portland²	83	79

	1,425	1,465

The Company's non-controlling interests included in the Consolidated Statement of Income were as follows:


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Non-controlling interest in TC PipeLines, LP¹	91	101	87
Preferred share dividends of TCPL	22	22	22
Non-controlling interest in Portland²	5	6	6

	118	129	115

1: Effective May 3, 2011, the non-controlling interest in TC PipeLines, LP increased from 61.8 per cent to 66.7 per cent due to the issuance of equity to non-controlling
interests in TC PipeLines, LP associated with the sale of 25 per cent interests in GTN LLC and Bison LLC pipelines from TransCanada to TC PipeLines, LP. The
non-controlling interest in TC PipeLines, LP from January 1, 2010 to May 3, 2011 was 61.8 per cent.
2: The non-controlling interests in Portland as at December 31, 2012 represented the 38.3 per cent interest not owned by TransCanada (2011 and 2010 – 38.3 per cent).

Preferred Shares of TCPL


at December 31	Number of Shares	Dividend Rate per Share	Redemption Price per Share	2012	2011

	(thousands)			(millions of Canadian dollars)	(millions of Canadian dollars)
Cumulative First Preferred Shares of Subsidiary
Series U	4,000	$2.80	$50.00	195	195
Series Y	4,000	$2.80	$50.00	194	194

				389	389

The authorized number of preferred shares of TCPL issuable in each series is unlimited. All of the cumulative first preferred shares of TCPL are without par value.

On or after October 15, 2013, TCPL may redeem the Series U preferred shares at $50 per share, and on or after March 5, 2014, TCPL may redeem the Series Y shares at $50 per share.

Cash Dividends
Cash dividends of $22 million or $2.80 per share were paid on the Series U and Series Y preferred shares in each of 2012, 2011 and 2010.

In 2012, TransCanada received fees of $3 million from TC PipeLines, LP (2011 and 2010 – $2 million) and $7 million from Portland (2011 and 2010 – $7 million) for services provided.

The entire disclosure for noncontrolling interest in consolidated subsidiaries, which could include the name of the subsidiary, the ownership percentage held by the parent, the ownership percentage held by the noncontrolling owners, the amount of the noncontrolling interest, the location of this amount on the balance sheet (when not reported separately), an explanation of the increase or decrease in the amount of the noncontrolling interest, the noncontrolling interest share of the net Income or Loss of the subsidiary, the location of this amount on the income statement (when not reported separately), the nature of the noncontrolling interest such as background information and terms, the amount of the noncontrolling interest represented by preferred stock, a description of the preferred stock, and the dividend requirements of the preferred stock.

EMPLOYEE POST-RETIREMENT BENEFITS

COMMON SHARES

12 Months Ended

Dec. 31, 2012

COMMON SHARES

COMMON SHARES

18. COMMON SHARES


		Number of Shares	Amount

		(thousands)	(millions of Canadian dollars)
Outstanding at January 1, 2010		684,359	11,338
	Dividend reinvestment and share purchase plan	10,670	378
	Exercise of options	1,201	29

Outstanding at December 31, 2010		696,230	11,745
	Dividend reinvestment and share purchase plan	5,371	202
	Exercise of options	2,260	64

Outstanding at December 31, 2011		703,861	12,011
	Exercise of options	1,600	58

Outstanding at December 31, 2012		705,461	12,069

Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares without par value.

Net Income per Share
Net income per share is calculated by dividing Net Income Attributable to Common Shares by the weighted average number of common shares outstanding. During the year, the weighted average number of common shares outstanding of 704.6 million and 705.7 million (2011 – 701.6 million and 702.8 million; 2010 – 690.5 million and 691.7 million) were used to calculate basic and diluted earnings per share, respectively. The increase in the weighted average number of shares for the diluted earnings per share calculation is due to the options exercisable under TransCanada's Stock Option Plan.

Stock Options


	Number of Options		Weighted Average Exercise Prices	Options Exercisable

	(thousands)			(thousands)
Outstanding at January 1, 2010	8,274		$30.56	6,212
Granted	1,367		$35.32
Exercised	(1,201	)	$22.04
Forfeited	(34	)	$27.35

Outstanding at December 31, 2010	8,406		$32.57	6,458
Granted	970		$38.02
Exercised	(2,260	)	$25.86
Forfeited	(16	)	$35.83

Outstanding at December 31, 2011	7,100		$35.44	5,165
Granted	1,978		$42.03
Exercised	(1,600	)	$33.13
Forfeited	(44	)	$36.55

Outstanding at December 31, 2012	7,434		$37.69	4,588

Stock options outstanding were as follows:


at December 31, 2012	Options Outstanding			Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life

	(thousands)		(years)	(thousands)		(years)
$30.10 to $31.97	1,093	$31.95	3.2	1,093	$31.95	3.2
$32.40 to $35.08	1,387	$34.64	4.0	1,160	$34.55	4.0
$35.23 to $37.93	1,202	$37.52	5.0	556	$37.22	4.9
$38.10 to $39.75	1,750	$38.83	1.7	1,750	$38.83	1.7
$41.65 to $45.29	2,002	$42.03	6.1	29	$41.87	5.9

	7,434	$37.69	3.9	4,588	$35.93	2.7

An additional 2.4 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2012. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $5.08 for the year ended December 31, 2012 (2011 – $2.94; 2010 – $5.76). The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest 33.3 per cent on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation, retirement or termination of the option holder's employment. The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions for 2012: 5.9 years of expected life (2011 and 2010 – 4.0 years); 1.6 per cent interest rate (2011 – 2.1 per cent; 2010 – 2.0 per cent); 19 per cent volatility (2011 – 14 per cent; 2010 – 27 per cent); 4.2 per cent dividend yield (2011 – 4.3 per cent; 2010 – 4.7 per cent) and a 15 per cent forfeiture rate (2011 – 15 per cent; 2010 – 15 per cent). Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. The amount expensed for stock options, with a corresponding increase in additional paid-in capital, was $5 million in 2012 (2011 – $5 million and 2010 – $4 million).

The total intrinsic value of options exercised in 2012 was $18 million (2011 – $34 million; 2010 – $17 million). As at December 31, 2012, the aggregate intrinsic value of the total options exercisable was $51 million and the total intrinsic value of options outstanding was $69 million. In 2012, the 1.0 million (2011 – 0.9 million; 2010 – 1.5 million) shares that vested had a fair value of $49 million (2011 – $42 million; 2010 – $57 million).

Shareholder Rights Plan
TransCanada's Shareholder Rights Plan is designed to provide the Board with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase two common shares of the Company for the then current market price of one.

Cash Dividends
Cash dividends of $1,226 million or $1.74 per common share were paid in 2012 (2011 – $961 million or $1.66 per common share, net of the Dividend Reinvestment Plan (DRP); 2010 – $710 million or $1.58 per common share, net of DRP).

Dividend Reinvestment Plan
Under the Company's DRP, eligible holders of common or preferred shares of TransCanada and preferred shares of TCPL can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with the dividends declared in April 2011, dividends payable to shareholders who participate in the DRP are satisfied with common shares purchased on the open market determined on the basis of the weighted average purchase price of such common shares. Previously, common shares issued in lieu of cash dividends under the DRP were issued from treasury at a discount to the average market price in the five days before dividend payment. The discount was set at three per cent in 2010, and was reduced to two per cent commencing with the dividends declared in February 2011 and was eliminated completely in April 2011. In 2011 and 2010, TransCanada issued 5.4 million and 10.7 million common shares from treasury in accordance with the DRP in lieu of making cash dividend payments of $202 million and $378 million respectively.

PREFERRED SHARES

12 Months Ended

Dec. 31, 2012

PREFERRED SHARES

PREFERRED SHARES

19. PREFERRED SHARES


at December 31	Number of Shares Authorized and Outstanding	Dividend Rate per Share	Redemption Price per Share	2012	2011

	(thousands)			(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares
Series 1	22,000	$1.15	$25.00	539	539
Series 3	14,000	$1.00	$25.00	343	343
Series 5	14,000	$1.10	$25.00	342	342

				1,224	1,224

1: Net of underwriting commissions and deferred income taxes.

The holders of the Series 1 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.92 per cent. The Series 1 preferred shares are redeemable by TransCanada on December 31, 2014 and on December 31 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 1 preferred shareholders have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.

The holders of the Series 3 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly, for the initial five-year period ending June 30, 2015. The dividend rate will reset on June 30, 2015 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.28 per cent. The Series 3 preferred shares are redeemable by TransCanada on June 30, 2015 and on June 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 3 preferred shareholders have the right to convert their shares into Series 4 cumulative redeemable first preferred shares on June 30, 2015 and on June 30 of every fifth year thereafter. The holders of Series 4 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.28 per cent.

The holders of the Series 5 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.10 per share, payable quarterly, for the initial five-and-a-half-year period ending January 30, 2016. The dividend rate will reset on January 30, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 1.54 per cent. The Series 5 preferred shares are redeemable by TransCanada on January 30, 2016 and on January 30 of every fifth year thereafter at a price of $25.00 per share plus all accrued and unpaid dividends.

The Series 5 preferred shareholders have the right to convert their shares into Series 6 cumulative redeemable first preferred shares on January 30, 2016 and on January 30 of every fifth year thereafter. The holders of Series 6 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.54 per cent.

Cash Dividends
In 2012, the Company made cash dividend payments of $25 million or $1.15 per Series 1 preferred share (2011 – $25 million or $1.15 per share, net of DRP; 2010 – $24 million or $1.15 per share, net of DRP), $14 million or $1.00 per Series 3 preferred share (2011 – $14 million or $1.00 per share, net of DRP; 2010 – $11 million or $0.8041 per share, net of DRP) and $16 million or $1.10 per Series 5 preferred share (2011 – $16 million or $1.10 per share, net of DRP; 2010 – $9 million or $0.3707 per share, net of DRP).

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2012

EMPLOYEE POST-RETIREMENT BENEFITS

20. EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plans increase annually by a portion of the increase in the Consumer Price Index. Past service costs are amortized over the expected average remaining service life of employees, which is approximately nine years (2011 – eight years; 2010 – eight years).

The Company also provides its employees with a Savings Plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Past service costs are amortized over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2012 (2011 – 12 years; 2010 – 12 years). In 2012, the Company expensed $24 million (2011 – $23 million, 2010 – $21 million) for the Savings Plan and DC Plans.

Total cash payments for employee post-retirement benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $114 million in 2012 (2011 – $93 million, 2010 – $127 million), including $24 million in 2012 (2011 – $23 million, 2010 – $21 million) related to the Savings Plan and DC Plans. In addition to these cash payments, in 2012 the Company provided a $48 million letter of credit to the Canadian DB Plan (2011 – $27 million), resulting in a total of $75 million provided to the Canadian DB Plan under letters of credit at December 31, 2012. The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2013, and the next required valuation will be as at January 1, 2014.


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Change in Benefit Obligation¹
Benefit obligation – beginning of year	1,836		1,622		170		159
Service cost	66		54		2		2
Interest cost	94		91		8		9
Employee contributions	4		4		1		1
Benefits paid	(79	)	(71	)	(9	)	(9	)
Actuarial loss	227		131		16		7
Foreign exchange rate changes	(6	)	5		(2	)	1

Benefit obligation – end of year	2,142		1,836		186		170

Change in Plan Assets
Plan assets at fair value – beginning of year	1,656		1,636		29		29
Actual return on plan assets	165		21		4		–
Employer contributions	83		62		7		8
Employee contributions	4		4		1		1
Benefits paid	(79	)	(71	)	(9	)	(9	)
Foreign exchange rate changes	(4	)	4		–		–

Plan assets at fair value – end of year	1,825		1,656		32		29

Funded Status – Plan Deficit	(317	)	(180	)	(154	)	(141	)

1: The benefit obligation for the Company's pension benefit plan represents the projected benefit obligation. The benefit obligation for the Company's other post-retirement
benefit plans represents the accumulated post-retirement benefit obligation.

The amounts recognized in the Company's Balance Sheet for its DB plans and other post-retirement benefits plans are as follows:


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Intangible and Other Assets (Note 10)	–		–		11		–
Other Long-Term Liabilities (Note 13)	(317	)	(180	)	(165	)	(141	)

	(317	)	(180	)	(154	)	(141	)

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Benefit obligation	(2,142	)	(1,836	)	(186	)	(170	)
Plan assets at fair value	1,825		1,656		32		29

Funded Status – Deficit	(317	)	(180	)	(154	)	(141	)

The accumulated benefit obligation for all DB pension plans at December 31, 2012 is $1,966 million (2011 – $1,691 million).

The funded status based on the accumulated benefit obligation for all DB Plans is as follows:


at December 31 (millions of Canadian dollars)	2012		2011

Accumulated benefit obligation	(1,966	)	(1,691	)
Plan assets at fair value	1,825		1,656

Funded Status – Deficit	(141	)	(35	)

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.


at December 31 (millions of Canadian dollars)	2012		2011

Accumulated benefit obligation	(1,966	)	(446	)
Plan assets at fair value	1,825		391

Funded Status – Deficit	(141	)	(55	)

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:

Asset Category


	Percentage of Plan Assets		Target Allocations
at December 31	2012	2011	2012

Debt securities	36%	39%	35% to 60%
Equity securities	64%	61%	40% to 65%

	100%	100%

Debt securities included the Company's debt of $2 million (0.1 per cent of total plan assets) and $2 million (0.1 per cent of total plan assets) at December 31, 2012 and 2011, respectively. Equity securities included the Company's common shares of $3 million (0.2 per cent of total plan assets) and $3 million (0.2 per cent of total plan assets) at December 31, 2012 and 2011, respectively. Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded.

The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into three categories based on a fair value hierarchy. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs, which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement.

at December 31
(millions of

Quoted Prices in
Active Markets
(Level I)

Significant Other Observable Inputs
(Level II)

Significant Unobservable Inputs
(Level III)

Total

Percentage of
Total Portfolio

Canadian dollars)

2012

2011

2012

2011

2012

2011

2012

2011

2012

2011

Asset Category

Cash and cash equivalents

–

Equity Securities:

Canadian

400

374

113

–

513

469

28%

28%

U.S.

309

251

–

347

306

19%

18%

International

263

231

–

294

256

16%

15%

Global

–

Fixed Income Securities:

Canadian Bonds:

Federal

–

314

303

–

314

303

17%

18%

Provincial

–

161

158

–

161

158

Municipal

–

Corporate

–

U.S. Bonds:

State

–

Corporate

–

International:

Corporate

–

Mortgage Backed

–

Other Investments:

Private Equity Funds

–

757

675

1,081

990

1,857

1,685

100%

100%

The following table presents the net change in the Level III fair value category:


(millions of Canadian dollars, pre-tax)	Private Equity Funds

Balance at December 31, 2010	21
Realized and unrealized losses	(2	)
Purchases and sales	1

Balance at December 31, 2011	20

Realized and unrealized losses	(1	)

Balance at December 31, 2012	19

The Company's expected funding contributions in 2013 are approximately $71 million for the DB Plans and approximately $33 million for the other post-retirement benefit plans, Savings Plan and DC Plans. In addition, the Company expects to provide a $59 million letter of credit to the Canadian DB Plan.

The following are estimated future benefit payments, which reflect expected future service:


(millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits

2013	90	9
2014	96	9
2015	101	10
2016	107	10
2017	111	11
2018 to 2022	636	58

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2012. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:


	Pension Benefit Plans		Other Post-Retirement Benefit Plans
at December 31	2012	2011	2012	2011

Discount rate	4.35%	5.05%	4.35%	5.10%
Rate of compensation increase	3.15%	3.15%

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:

Pension
Benefit Plans

Other
Post-Retirement
Benefit Plans

year ended December 31

2012

2011

2010

2012

2011

2010

Discount rate

5.05%

5.55%

6.00%

5.10%

5.60%

6.00%

Expected long-term rate of return on plan assets

6.70%

6.95%

6.40%

6.40%

7.80%

Rate of compensation increase

3.15%

3.10%

3.20%

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.

A 7.5 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2020 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:


(millions of Canadian dollars)	Increase	Decrease

Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	17	(14	)

The Company's net benefit cost is as follows:


year ended December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2010		2012		2011		2010

Service cost	66		54		50		2		2		2
Interest cost	94		91		89		8		9		9
Expected return on plan assets	(113	)	(114	)	(108	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	18		10		5		1		1		1
Amortization of past service cost	2		2		2		1		–		–
Amortization of regulatory asset	19		12		5		1		1		1
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2

Net Benefit Cost Recognized	86		55		43		13		13		13

Pre-tax amounts recognized in AOCI were as follows:


at December 31	2012		2011		2010
(millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits

Net loss	362	33	282	29	179	24
Prior service cost	5	2	7	2	9	2

	367	35	289	31	188	26

The estimated net loss and prior service cost for the DB Plans that will be amortized from AOCI into net periodic benefit cost in 2013 are $31 million and $2 million, respectively. The estimated net loss and prior service cost for the other post-retirement plans that will be amortized from AOCI into net periodic benefit cost in 2013 is $2 million and nil, respectively.

Pre-tax amounts recognized in OCI were as follows:


at December 31	2012				2011				2010
(millions of Canadian dollars)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to OCI	(19	)	(1	)	(10	)	(1	)	(5	)	(1	)
Amortization of prior service costs from AOCI to OCI	(2	)	–		(2	)	–		(2	)	–
Funded status adjustment	99		5		113		6		15		4

	78		4		101		5		8		3

The entire disclosure for pension and other postretirement benefits.

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2012

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

21. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview
TransCanada has exposure to market risk and counterparty credit risk. TransCanada engages in risk management activities with the objective of mitigating the impact of these risks on earnings, cash flow and, ultimately, shareholder value.

Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by risk management and internal audit personnel. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk
The Company constructs and invests in large infrastructure projects, purchases and sells energy commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. Derivative contracts used to manage market risk generally consist of the following:

•: Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices.
•: Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.
•: Options – contractual agreements that convey the right, but not the obligation, of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the risk of changes in interest rates, foreign exchange rates and commodity prices.

Where possible, derivative instruments are designated as hedges, but in some cases derivatives do not meet the specific criteria for hedge accounting treatment and are accounted for at fair value with changes in fair value recorded in Net Income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period, however, the Company enters into the arrangements as they are considered to be effective economic hedges.

Commodity Price Risk
The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. A number of strategies are used to mitigate these exposures, including the following:

•: Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to mitigate operational and price risks in its asset portfolio.
•: The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.
•: The Company's power sales commitments are fulfilled through power generation or purchased through contracts, thereby reducing the Company's exposure to fluctuating commodity prices.
•: The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

The Company assesses its commodity contracts and derivative instruments used to manage commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they or certain aspects of them meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but fair value accounting is not required, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's normal purchases and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain exemptions.

Natural Gas Storage Commodity Price Risk
TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement.

Foreign Exchange and Interest Rate Risk
Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.

A portion of TransCanada's earnings from its Natural Gas Pipelines, Oil Pipelines and Energy segments is generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada's net income. This foreign exchange impact is partially offset by U.S. dollar-denominated financing costs and by the Company's hedging activities. TransCanada has a greater exposure to U.S. currency fluctuations than in prior years due to growth in its U.S. operations, partially offset by increased levels of U.S. dollar-denominated interest expense.

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its debt and other U.S. dollar-denominated transactions. Certain of the realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements.

TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.

Net Investment in Foreign Operations
The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At December 31, 2012, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $11.1 billion (US$11.2 billion) (2011 – $10 billion (US$9.8 billion)) and a fair value of $14.3 billion (US$14.4 billion) (2011 – $12.7 billion (US$12.5 billion)). At December 31, 2012, $71 million (December 31, 2011 – $79 million) was included in Other Current Assets, $47 million (December 31, 2011 – $66 million) was included in Intangible and Other Assets, $6 million (December 31, 2011 – $15 million) was included in Accounts Payable and Other, and $30 million (December 31, 2011 – $41 million) was included in Other Long-Term Liabilities for the fair value of the forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.

The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:

Asset/(Liability)


	2012		2011
at December 31 (millions of Canadian dollars)	Fair Value¹	Notional or Principal Amount	Fair Value¹		Notional or Principal Amount

U.S. dollar cross-currency swaps (maturing 2013 to 2019)²	82	US 3,800	93		US 3,850
U.S. dollar forward foreign exchange contracts (maturing 2013)	–	US 250	(4	)	US 725

	82	US 4,050	89		US 4,575

1: Fair values equal carrying values.
2: Net Income in 2012 included net realized gains of $30 million (2011 – gains of $27 million) related to the interest component of cross-currency swap settlements.

Counterparty Credit Risk
Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Company.

Counterparty credit risk is managed through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits, using contract netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. The Company believes these measures minimize its counterparty credit risk but there is no certainty that they will protect it against all material losses.

TransCanada's maximum counterparty credit exposure with respect to financial instruments at the Balance Sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and notes, and loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts receivable and other, and Available for sale assets in the Non-Derivative Financial Instruments Summary table located in the Fair Values section of this note. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2012, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

At December 31, 2012, the Company had a credit risk concentration of $259 million (2011 – $274 million) due from a counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.

TransCanada has significant credit and performance exposures to financial institutions as they provide committed credit lines and cash deposit facilities, critical liquidity in the foreign exchange derivative, interest rate derivative and energy wholesale markets, and letters of credit to mitigate TransCanada's exposure to non-creditworthy counterparties.

As a level of uncertainty continues to exist in the global financial markets, TransCanada continues to closely monitor and reassess the creditworthiness of its counterparties. This has resulted in TransCanada reducing or mitigating its exposure to certain counterparties where it was deemed warranted and permitted under contractual terms. As part of its ongoing operations, TransCanada must balance its market and counterparty credit risks when making business decisions.

Fair Values

Non-derivative Instruments
Certain financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Intangible and Other Assets, Notes Payable, Accounts Payable, Accrued Interest and Other Long-Term Liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. The fair value of the Company's Notes Receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments. The fair value of available for sale assets has been calculated using quoted market prices where available.

Derivative Instruments
The fair value of foreign exchange and interest rate derivatives have been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale investments has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used.

Credit risk has been taken into consideration when calculating the fair value of derivatives, Notes Receivable and Long-Term Debt.

Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as follows:


	2012		2011
at December 31 (millions of Canadian dollars)	Carrying Amount¹	Fair Value²	Carrying Amount¹	Fair Value²

Financial Assets
Cash and cash equivalents	551	551	654	654
Accounts receivable and other³	1,288	1,337	1,359	1,403
Available for sale assets³	44	44	23	23

	1,883	1,932	2,036	2,080

Financial Liabilities⁴
Notes payable	2,275	2,275	1,863	1,863
Accounts payable and other long-term liabilities⁵	1,535	1,535	1,329	1,329
Accrued interest	368	368	365	365
Long-term debt	18,913	24,573	18,659	23,757
Junior subordinated notes	994	1,054	1,016	1,027

	24,085	29,805	23,232	28,341

1: Recorded at amortized cost, except for $350 million (2011 – $350 million) of Long-Term Debt that is attributed to hedged risk and recorded at fair value. This debt, which is recorded at fair value on a recurring
basis, is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.
2: The fair value measurement of financial assets and liabilities recorded at amortized cost for which the fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the
income approach based on interest rates from external data service providers.
3: At December 31, 2012, the Consolidated Balance Sheet included financial assets of $1.1 billion (2011 – $1.1 billion) in Accounts Receivable, $40 million (2011 – $41 million)
in Other Current Assets and $240 million (2011 – $247 million) in Intangible and Other Assets.
4: Consolidated Net Income in 2012 included losses of $10 million (2011 – losses of $13 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest
rate swap fair value hedging relationships on US$350 million of debt at December 31, 2012 (2011 – US$350 million). There were no other unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
5: At December 31, 2012, the Consolidated Balance Sheet included financial liabilities of $1.5 billion (2011 – $1.2 billion) in Accounts Payable and $38 million (2011 – $137 million)
in Other Long-Term Liabilities.

The following tables detail the remaining contractual maturities for TransCanada's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2012:

Contractual Repayments of Financial Liabilities¹


	Payments Due by Period
(millions of Canadian dollars)	Total	2013	2014 and 2015	2016 and 2017	2018 and Thereafter

Notes payable	2,275	2,275	–	–	–
Long-term debt	18,913	894	2,531	1,769	13,719
Junior subordinated notes	994	–	–	–	994

	22,182	3,169	2,531	1,769	14,713

1: The anticipated timing of settlement of derivative contracts is presented in the Derivatives Instrument Summary in this note.

Interest Payments on Financial Liabilities


	Payments Due by Period
(millions of Canadian dollars)	Total	2013	2014 and 2015	2016 and 2017	2018 and Thereafter

Long-term debt	15,377	1,154	2,125	1,908	10,190
Junior subordinated notes	3,443	63	126	126	3,128

	18,820	1,217	2,251	2,034	13,318

Derivative Instruments Summary
Information for the Company's derivative instruments for 2012, excluding hedges of the Company's net investment in foreign operations, is as follows:


at December 31			2012
(all amounts in Canadian millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Instruments Held for Trading¹
Fair Values²
	Assets		$139		$88		$1		$14
	Liabilities		$(176	)	$(104	)	$(2	)	$(14	)
Notional Values
	Volumes³
		Purchases	31,135		83		–		–
		Sales	31,066		65		–		–
	Canadian dollars		–		–		–		620
	U.S. dollars		–		–		US 1,408		US 200
	Cross-currency		–		–		–		–
Net unrealized (losses)/gains in the year⁴			$(30	)	$2		$(1	)	$–
Net realized gains/(losses) in the year⁴			$5		$(10	)	$26		$–
Maturity dates			2013-2017		2013-2016		2013		2013-2016
Derivative Instruments in Hedging Relationships^5,6
Fair Values²
	Assets		$76		$–		$–		$10
	Liabilities		$(97	)	$(2	)	$(38	)	$–
Notional Values
	Volumes³
		Purchases	15,184		1		–		–
		Sales	7,200		–		–		–
	U.S. dollars		–		–		US 12		US 350
	Cross-currency		–		–		136/US 100		–
Net realized (losses)/gains in the year⁴			$(130	)	$(23	)	$–		$7
Maturity dates			2013-2018		2013		2013-2014		2013-2015

1: All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been
designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
2: Fair values equal carrying values.
3: Volumes for power and natural gas derivatives are in GWh and billion cubic feet (Bcf), respectively.
4: Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate
and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative
instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.
5: All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $10 million and a notional amount of
US$350 million. In 2012, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2012, the Company did not record any amounts in Net Income related to
ineffectiveness for fair value hedges.
6: In 2012, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivative Instruments Summary
Information for the Company's derivative instruments for 2011, excluding hedges of the Company's net investment in foreign operations, is as follows:


at December 31			2011
(all amounts in Canadian millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Instruments Held for Trading¹
Fair Values²
	Assets		$185		$176		$3		$22
	Liabilities		$(192	)	$(212	)	$(14	)	$(22	)
Notional Values
	Volumes³
		Purchases	21,905		103		–		–
		Sales	21,334		82		–		–
	Canadian dollars		–		–		–		684
	U.S. dollars		–		–		US 1,269		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁴			$(2	)	$(50	)	$(4	)	$1
Net realized gains/(losses) in the year⁴			$42		$(74	)	$10		$1
Maturity dates			2012-2016		2012-2016		2012		2012-2016
Derivative Instruments in Hedging Relationships^5,6
Fair Values²
	Assets		$16		$3		$–		$13
	Liabilities		$(277	)	$(22	)	$(38	)	$(1	)
Notional Values
	Volumes³
		Purchases	17,188		8		–		–
		Sales	8,061		–		–		–
	U.S. dollars		–		–		US 73		US 600
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁴			$(165	)	$(17	)	$–		$(16	)
Maturity dates			2012-2017		2012-2013		2012-2014		2012-2015

1: All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
2: Fair values equal carrying values.
3: Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
4: Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and
losses on interest rate and foreign exchange derivative instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion
of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
5: All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $13 million and a
notional amount of US$350 million. In 2011, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2011, the Company did not record any amounts

in Net Income related to ineffectiveness for fair value hedges.
6: In 2011, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Balance Sheet Presentation of Derivative Instruments
The fair value of the derivative instruments in the Company's Balance Sheet was as follows:


at December 31 (millions of Canadian dollars)	2012		2011

Current
Other current assets (Note 5)	259		361
Accounts payable and other (Note 12)	(283	)	(485	)
Long Term
Intangible and other assets (Note 10)	187		202
Other long-term liabilities (Note 13)	(186	)	(349	)

Derivatives in Cash Flow Hedging Relationships
The components of OCI related to derivatives in cash flow hedging relationships are as follows:

Cash Flow Hedges¹

Power

Natural Gas

Foreign Exchange

Interest

year ended December 31
(millions of Canadian dollars, pre-tax)

2012

2011

2012

2011

2012

2011

2012

2011

Change in fair value of derivative instruments recognized in OCI (effective portion)

(263

)

(21

)

(59

)

–

)

Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion)

147

100

–

Gains and losses on derivative instruments recognized in earnings (ineffective portion)

–

1: No amounts have been excluded from the assessment of hedge effectiveness.

Credit Risk Related Contingent Features
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at December 31, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $37 million (2011 – $110 million), for which the Company has provided collateral of nil (2011 – $28 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2012, the Company would have been required to provide additional collateral of $37 million (2011 – $82 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

Fair Value Hierarchy

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.

In Level II, the fair value of interest rate and foreign exchange derivative assets and liabilities is determined using the income approach. The fair value of power and natural gas commodity assets and liabilities is determined using the market approach. Under both approaches, valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Such inputs include published exchange rates, interest rates, interest rate swap curves, yield curves, and broker quotes from external data service providers. Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in 2012 or 2011.

In Level III, the fair value of assets and liabilities measured on a recurring basis is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II. There were no transfers out of Level II and into Level III in 2012 or 2011.

Long-dated commodity transactions in certain markets where liquidity is low are included in Level III of the fair value hierarchy, as the related commodity prices are not readily observable. Long-term electricity prices are estimated using a third-party modelling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Long-term prices are reviewed by management and the Board on a periodic basis. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas would result in a lower fair value measurement of contracts included in Level III. The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:


December 31 (millions of Canadian dollars,		Quoted Prices in Active Markets (Level I)				Significant Other Observable Inputs (Level II)				Significant Unobservable Inputs (Level III)				Total
pre-tax)		2012		2011		2012		2011		2012		2011		2012		2011

Derivative Instrument Assets:
	Interest rate contracts	–		–		24		35		–		–		24		35
	Foreign exchange contracts	–		–		119		142		–		–		119		142
	Power commodity contracts	–		–		213		201		2		–		215		201
	Gas commodity contracts	75		124		13		55		–		–		88		179
Derivative Instrument Liabilities:
	Interest rate contracts	–		–		(14	)	(23	)	–		–		(14	)	(23	)
	Foreign exchange contracts	–		–		(76	)	(102	)	–		–		(76	)	(102	)
	Power commodity contracts	–		–		(269	)	(454	)	(4	)	(15	)	(273	)	(469	)
	Gas commodity contracts	(95	)	(208	)	(11	)	(26	)	–		–		(106	)	(234	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	44		23		–		–		–		–		44		23

		24		(61	)	(1	)	(172	)	(2	)	(15	)	21		(248	)

The following table presents the net change in the Level III fair value category:


(millions of Canadian dollars, pre-tax)	Derivatives^1,2

Balance at December 31, 2010	(8	)
New contracts	1
Settlements	2
Transfers out of Level III	3
Total losses included in OCI	(13	)

Balance at December 31, 2011	(15	)

Settlements	(1	)
Transfers out of Level III	(21	)
Total gains included in Net Income	11
Total gains included in OCI	24

Balance at December 31, 2012	(2	)

1: The fair value of derivative assets and liabilities is presented on a net basis.
2: At December 31, 2012, there were unrealized gains included in Net Income attributable to derivatives that were still held at the reporting date of $1 million (2011 – nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $4 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2012.

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2012

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL

22. CHANGES IN OPERATING WORKING CAPITAL


year ended December 31 (millions of Canadian dollars)	2012	2011		2010

Decrease/(increase) in accounts receivable	67	(15	)	(286	)
Decrease in inventories	27	3		25
Decrease/(increase) in other current assets	66	(27	)	(76	)
Increase in accounts payable and other	127	266		60
Increase/(decrease) in accrued interest	–	8		(8	)

Decrease/(Increase) in Operating Working Capital	287	235		(285	)

ACQUISITIONS AND DISPOSITIONS

12 Months Ended

Dec. 31, 2012

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

23. ACQUISITIONS AND DISPOSITIONS

Energy

CrossAlta
On December 18, 2012, TransCanada purchased BP's 40 per cent interest in the assets of the Crossfield Gas Storage facility and BP's interest in CrossAlta Gas Storage & Services Ltd. (collectively CrossAlta) for $214 million in cash, net of cash acquired, resulting in the Company owning and operating 100 per cent of these operations. The acquisition will enhance TransCanada's ability to deliver reliable services to the natural gas markets in western Canada and is consistent with TransCanada's growth strategy for its natural gas storage business.

The Company measured the assets and liabilities acquired at fair value and the transaction resulted in no goodwill. Pro-forma revenues and earnings for the years ended December 31, 2012 and 2011, assuming the acquisition had occurred at the beginning of the period, would not be materially different from reported results.

Upon acquisition, TransCanada began consolidating CrossAlta. Prior to the acquisition, TransCanada applied equity accounting to its 60 per cent ownership interest in CrossAlta.

Natural Gas Pipelines

TC PipeLines, LP
On May 3, 2011, TransCanada completed the sale of a 25 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$605 million which included US$81 million of long-term debt, or 25 per cent of GTN LLC's outstanding debt. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

On May 3, 2011, TC PipeLines, LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Net proceeds of approximately US$331 million from this offering were used to partially fund the acquisition. The acquisition was also funded by draws of US$61 million on TC PipeLines, LP's bridge loan facility and US$125 million on its US$250 million senior revolving credit facility.

As part of this offering, TransCanada made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in TC PipeLines, LP and did not purchase any other units. As a result of the common units offering, TransCanada's ownership in TC PipeLines, LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Additional Paid-In Capital.

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2012

COMMITMENTS, CONTINGENCIES AND GUARANTEES

COMMITMENTS, CONTINGENCIES AND GUARANTEES

24. COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating Leases
Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment are approximately as follows:


year ended December 31 (millions of Canadian dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases		Net Payments

2013	82	(8	)	74
2014	80	(8	)	72
2015	80	(7	)	73
2016	81	(4	)	77
2017	80	(2	)	78
2018 and thereafter	374	(1	)	373

	777	(30	)	747

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 10 years. Net rental expense on operating leases in 2012 was $84 million (2011 – $79 million; 2010 – $80 million).

TransCanada's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from operating leases in the above table, as these payments are dependent upon plant availability and other factors. TransCanada's share of payments under the PPAs in 2012 was $303 million (2011 – $394 million; 2010 – $363 million). The generating capacities and expiry dates of the PPAs are as follows:


	Megawatts	Expiry Date

Sundance A	560	December 31, 2017
Sundance B¹	353	December 31, 2020
Sheerness	756	December 31, 2020

1: Held within TransCanada's 50 per cent interest in ASTC Power Partnership.

TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.

Other Commitments
At December 31, 2012, TransCanada was committed to Natural Gas Pipelines capital expenditures totalling approximately $1,322 million, primarily related to construction costs related to the Alberta System and Mexico pipeline projects.

At December 31, 2012, the Company was committed to Oil Pipelines capital expenditures totalling approximately $1,732 million, primarily related to construction costs of Keystone XL and the Gulf Coast Project. At December 31, 2012, the Company was committed to Energy capital expenditures totalling approximately $62 million and related to capital costs of the Napanee Generating Station.

On December 15, 2011, TransCanada agreed to purchase nine Ontario solar projects from Canadian Solar Solutions Inc., with a combined capacity of 86 MW, for $476 million. Under the terms of the agreement, each of the nine solar projects will be developed and constructed by Canadian Solar Solutions Inc. using photovoltaic panels. TransCanada will purchase each project once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the Ontario Power Authority (OPA) under the Feed-in Tariff program in Ontario. TransCanada anticipates the projects will be placed in service between early 2013 and late 2014, subject to regulatory approvals.

Contingencies
TransCanada is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2012, the Company had accrued approximately $37 million (2011 – $49 million) related to operating facilities, which represents the estimated amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees
TransCanada and its joint venture partners on Bruce B, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The Bruce B guarantees have terms to 2018 except for one guarantee with no termination date that has no exposure associated with it. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement, an agreement with the OPA to restart the Bruce A power generation units, and certain other financial obligations. The Bruce A guarantees have terms to 2019. TransCanada's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $897 million at December 31, 2012. The carrying amount of these Bruce Power guarantees at December 31, 2012 is estimated to be $10 million which has been included in Other Long-Term Liabilities. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. The guarantees have terms ranging from 2013 to 2040. TransCanada's share of the potential exposure under these assurances was estimated at December 31, 2012 to range from $43 million to a maximum of $89 million. The carrying amount of these guarantees at December 31, 2012 is estimated to be $7 million, which has been included in Other Long-Term Liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

SUBSEQUENT EVENT

12 Months Ended

Dec. 31, 2012

SUBSEQUENT EVENT

SUBSEQUENT EVENT

25. SUBSEQUENT EVENT

On January 15, 2013, TransCanada PipeLines Limited issued US$750 million of Senior Notes maturing January 15, 2016 and bearing interest at 0.75 per cent.

ACCOUNTING POLICIES (Policies)	12 Months Ended
ACCOUNTING POLICIES (Policies)	Dec. 31, 2012
ACCOUNTING POLICIES
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.
Use of Estimates and Judgements	Use of Estimates and Judgements In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies summarized below.
Regulation	Regulation In Canada, regulated natural gas pipelines and oil pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, oil pipelines and regulated storage assets are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission of Mexico. The Company's Canadian and U.S. natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. RRA is not applicable to the Keystone Pipeline System and the Company's Mexican natural gas pipelines and, as a result, the regulators' decisions regarding operations and tolls on these pipelines generally do not have an impact on timing of recognition of revenues and expenses.
Revenue Recognition	Revenue Recognition *Natural Gas and Oil Pipelines* Revenues from the Company's natural gas and oil pipelines, with the exception of Canadian natural gas pipelines which are subject to rate regulation, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or oil are made. The U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized when appropriate. Revenues from Canadian natural gas pipelines subject to rate regulation are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include an appropriate return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are periodically subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received. Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others. *Energy* Power Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note. Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Inventories	Inventories Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.
Plant, Property and Equipment	Plant, Property and Equipment *Natural Gas Pipelines* Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, Property and Equipment and the equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation. *Oil Pipelines* Plant, property and equipment for oil pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When oil pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings. *Energy* Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings. *Corporate* Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Company reviews long-lived assets, such as plant, property and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
Acquisitions and Goodwill	Acquisitions and Goodwill The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition with limited exception. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If TransCanada concludes that it is not more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.
Power Purchase Arrangements	Power Purchase Arrangements A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. The PPAs under which TransCanada buys power are accounted for as operating leases. The initial payments for these PPAs were recognized in Intangible and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.
Income Taxes	Income Taxes The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. Recorded ARO relates to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, oil pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.
Environmental Liabilities	Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. Emission allowances or credits purchased for compliance are recorded on the Balance Sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options	Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period, with an offset to Additional Paid-In Capital. Upon exercise of stock options, amounts originally recorded against Additional Paid-In Capital are reclassified to Common Shares. The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits	Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive Loss (AOCI) over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the average remaining service life of active employees.
Foreign Currency Transactions and Translation	Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the company or reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt has been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments are recorded on the balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify and are designated for hedge accounting treatment, which includes fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest Income and Other and Interest Expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net Income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in Net Income in the period of change. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory Assets or Regulatory Liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in Net Income.
Long-Term Debt Transaction Costs	Long-Term Debt Transaction Costs The Company records long-term debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.
Guarantees	Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company or partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Other Long-Term Liabilities.

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2012

SEGMENTED INFORMATION

Schedule of segmented information


year ended December 31, 2012 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total

Revenues	4,264		1,039		2,704		–		8,007
Income from equity investments	157		–		100		–		257
Plant operating costs and other	(1,365	)	(296	)	(819	)	(97	)	(2,577	)
Commodity purchases resold	–		–		(1,049	)	–		(1,049	)
Property taxes	(315	)	(45	)	(74	)	–		(434	)
Depreciation and amortization	(933	)	(145	)	(283	)	(14	)	(1,375	)

	1,808		553		579		(111	)	2,829

Interest expense									(976	)
Interest income and other									85

Income before income taxes									1,938
Income tax expense									(466	)

Net Income									1,472
Net Income Attributable to Non-Controlling Interests									(118	)

Net Income Attributable to Controlling Interests									1,354
Preferred Share Dividends									(55	)

Net Income Attributable to Common Shares									1,299


year ended December 31, 2011 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines¹		Energy		Corporate		Total

Revenues	4,244		827		2,768		–		7,839
Income from equity investments	159		–		256		–		415
Plant operating costs and other	(1,221	)	(209	)	(842	)	(86	)	(2,358	)
Commodity purchases resold	–		–		(991	)	–		(991	)
Property taxes	(307	)	(31	)	(72	)	–		(410	)
Depreciation and amortization	(923	)	(130	)	(261	)	(14	)	(1,328	)

	1,952		457		858		(100	)	3,167

Interest expense									(937	)
Interest income and other									55

Income before income taxes									2,285
Income tax expense									(575	)

Net Income									1,710
Net Income Attributable to Non-Controlling Interests									(129	)

Net Income Attributable to Controlling Interests									1,581
Preferred Share Dividends									(55	)

Net Income Attributable to Common Shares									1,526

1: Commencing in February 2011, TransCanada began recording earnings for the Keystone Pipeline System.


year ended December 31, 2010 (millions of Canadian dollars)	Natural Gas Pipelines		Oil Pipelines	Energy		Corporate		Total

Revenues	4,122		–	2,730		–		6,852
Income from equity investments	153		–	300		–		453
Plant operating costs and other	(1,165	)	–	(805	)	(99	)	(2,069	)
Commodity purchases resold	–		–	(1,178	)	–		(1,178	)
Property taxes	(294	)	–	(71	)	–		(365	)
Depreciation and amortization	(913	)	–	(247	)	–		(1,160	)
Valuation provision	(146	)	–	–		–		(146	)

	1,757		–	729		(99	)	2,387

Interest expense								(701	)
Interest income and other								94

Income before income taxes								1,780
Income tax expense								(387	)

Net Income								1,393
Net Income Attributable to Non-Controlling Interests								(115	)

Net Income Attributable to Controlling Interests								1,278
Preferred Share Dividends								(45	)

Net Income Attributable to Common Shares								1,233

Schedule of total assets


at December 31 (millions of Canadian dollars)	2012	2011

Natural Gas Pipelines	23,210	23,161
Oil Pipelines	10,485	9,440
Energy	13,157	13,269
Corporate	1,481	1,468

	48,333	47,338

Schedule of geographic information


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Revenues¹
Canada – domestic	3,527	3,929	3,178
Canada – export	1,121	1,087	838
United States	3,252	2,752	2,796
Mexico	107	71	40

	8,007	7,839	6,852

1: Revenues are attributed based on the country in which the product or service originated.


at December 31 (millions of Canadian dollars)	2012	2011

Plant, Property and Equipment
Canada	18,054	17,552
United States	14,904	14,388
Mexico	755	527

	33,713	32,467

Schedule of capital expenditures


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Natural Gas Pipelines	1,389	917	1,192
Oil Pipelines	1,145	1,204	2,696
Energy	24	384	473
Corporate	37	8	15

	2,595	2,513	4,376

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2012

OTHER CURRENT ASSETS

Schedule of other current assets


at December 31 (millions of Canadian dollars)	2012	2011

Fair value of derivative contracts (Note 21)	259	361
Deferred income tax assets (Note 15)	290	248
Regulatory assets (Note 8)	178	178
Other	270	327

	997	1,114

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2012

PLANT, PROPERTY AND EQUIPMENT

Schedule of plant, property and equipment


		2012			2011
at December 31 (millions of Canadian dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Natural Gas Pipelines¹
Canadian Mainline
	Pipeline	8,801	5,192	3,609	8,785	4,958	3,827
	Compression	3,370	1,880	1,490	3,362	1,765	1,597
	Metering and other	391	182	209	383	175	208

		12,562	7,254	5,308	12,530	6,898	5,632
	Under construction	163	–	163	28	–	28

		12,725	7,254	5,471	12,558	6,898	5,660

Alberta System
	Pipeline	7,214	3,221	3,993	6,701	3,062	3,639
	Compression	1,885	1,177	708	1,778	1,109	669
	Metering and other	958	420	538	931	409	522

		10,057	4,818	5,239	9,410	4,580	4,830
	Under construction	463	–	463	368	–	368

		10,520	4,818	5,702	9,778	4,580	5,198

ANR
	Pipeline	864	49	815	858	47	811
	Compression	514	72	442	510	72	438
	Metering and other	520	81	439	524	59	465

		1,898	202	1,696	1,892	178	1,714
	Under construction	63	–	63	20	–	20

		1,961	202	1,759	1,912	178	1,734

Other Natural Gas Pipelines
	GTN	1,565	411	1,154	1,589	370	1,219
	Great Lakes	1,544	750	794	1,577	741	836
	Foothills	1,634	1,062	572	1,630	1,005	625
	Mexico	536	59	477	547	39	508
	Other²	1,548	226	1,322	1,576	187	1,389

		6,827	2,508	4,319	6,919	2,342	4,577
	Under construction	297	–	297	33	–	33

		7,124	2,508	4,616	6,952	2,342	4,610

		32,330	14,782	17,548	31,200	13,998	17,202

Oil Pipelines
Keystone
	Pipeline	4,897	177	4,720	4,904	80	4,824
	Pumping equipment	1,560	75	1,485	1,502	38	1,464
	Tanks and other	372	23	349	548	15	533

		6,829	275	6,554	6,954	133	6,821
Under construction³		3,678	–	3,678	2,433	–	2,433

		10,507	275	10,232	9,387	133	9,254

Energy
Natural Gas – Ravenswood		1,799	290	1,509	1,799	220	1,579
Natural Gas – Other⁴		2,975	746	2,229	3,002	665	2,337
Hydro		634	106	528	620	90	530
Wind⁵		907	118	789	843	88	755
Natural Gas Storage⁶		677	83	594	454	78	376
Other		134	86	48	131	83	48

		7,126	1,429	5,697	6,849	1,224	5,625
Under construction – Other		136	–	136	308	–	308

		7,262	1,429	5,833	7,157	1,224	5,933

Corporate		154	54	100	129	51	78

		50,253	16,540	33,713	47,873	15,406	32,467

1: In 2012, the Company capitalized $32 million (2011 – $23 million) relating to the equity portion of AFUDC for natural gas pipelines with a corresponding amount recorded in Interest Income and Other.
2: Includes in service assets of Bison, Portland, North Baja, Tuscarora and Ventures LP. Bison went in service in January 2011.
3: Includes $2.0 billion and $1.5 billion for Keystone XL and the Gulf Coast Project, respectively, at December 31, 2012 (2011 – $1.5 billion and $0.9 billion, respectively). Keystone XL remains subject to regulatory approvals.
4: Includes facilities with long-term PPAs that are accounted for as operating leases, including Coolidge which went in service in May 2011. The cost and accumulated depreciation of these facilities
were $601 million and $55 million, respectively, at December 31, 2012 (2011 – $605 million and $34 million, respectively). Revenues of $73 million were recognized in 2012 (2011 – $53 million; 2010 – $15 million)
through the sale of electricity under the related PPAs.
5: Includes Cartier phase two of Gros-Morne effective November 2012, phase one of Gros-Morne effective November 2011, and Montagne-Sèche effective November 2011.
6: Includes acquisition in December 2012 of BP's 40 per cent interest in the assets of the Crossfield Gas Storage facility and BP's interest in CrossAlta Gas Storage & Services Ltd.

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2012

GOODWILL

Schedule of goodwill recorded on the entity's acquisitions in the U.S.


(millions of Canadian dollars)	Natural Gas Pipelines		Energy		Total

Balance at January 1, 2011	2,634		823		3,457
Foreign exchange rate changes	59		18		77

Balance at December 31, 2011	2,693		841		3,534
Foreign exchange rate changes	(58	)	(18	)	(76	)

Balance at December 31, 2012	2,635		823		3,458

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

Schedule of regulatory assets and liabilities

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2012

RATE-REGULATED BUSINESSES


at December 31 (millions of Canadian dollars)	2012	2011	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	1,122	1,178	n/a
Operating and debt-service regulatory assets²	171	172	1
Adjustment account³	80	82	30
Other⁴	434	430	n/a

	1,807	1,862
Less: Current portion included in Other Current Assets	178	178

	1,629	1,684

Regulatory Liabilities
Foreign exchange on long-term debt⁵	150	184	1-17
Operating and debt-service regulatory liabilities²	84	135	1
Other⁴	134	117	n/a

	368	436
Less: Current portion included in Accounts Payable	100	139

	268	297

1: These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory
assets are not included in rate base and do not yield a return on investment during the recovery period.
2: Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in
determining tolls for the following calendar year. Pre-tax operating results in 2012 would have been $50 million lower (2011 – $102 million higher) had these amounts not been recorded
as regulatory assets and liabilities.
3: A regulatory adjustment account of $85 million was established and agreed upon by Canadian Mainline stakeholders to reduce tolls in 2010. Amortization of the adjustment account
commenced in 2011 at the composite depreciation rate.
4: Pre-tax operating results in 2012 would have been $97 million higher (2011 – $106 million lower) had these amounts not been recorded as regulatory assets and liabilities.
5: Foreign exchange on long-term debt of the Canadian Mainline, Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated
debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized
when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, U.S. GAAP would have
required the inclusion of these unrealized gains or losses in Net Income.

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2012

EQUITY INVESTMENTS

Schedule of equity investments


		Income/(Loss) from Equity Investments				Equity Investments
	Ownership Interest as at	year ended December 31				at December 31
(millions of Canadian dollars)	December 31, 2012	2012		2011	2010	2012	2011

Natural Gas Pipelines
Northern Border¹		72		75	69	511	545
Iroquois	44.5%	41		40	40	174	181
TQM	50.0%	16		17	16	80	82
Other	Various	28		27	28	60	72
Energy
Bruce A	48.9%	(149	)	33	35	4,033	3,561
Bruce B	31.6%	163		77	138	69	115
ASTC Power Partnership	50.0%	40		84	41	42	58
Portlands Energy	50.0%	28		33	33	341	313
CrossAlta²		10		23	45	n/a	18
Other	Various	8		6	8	56	132

		257		415	453	5,366	5,077

1: The results reflect a 50 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2012, TransCanada had an ownership interest in TC PipeLines, LP of 33.3 per cent
(2011 – 33.3 per cent; 2010 – 38.2 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 16.7 per cent (2011 – 16.7 per cent; 2010 – 19.1 per cent).
2: In 2011, Property, Plant and Equipment included $63 million of assets owned directly by TransCanada through an undivided interest in the Crossfield joint venture which were utilized in the operations of the CrossAlta joint venture.
In December 2012, TransCanada acquired the remaining 40 per cent interest in CrossAlta to bring the Company's ownership interest to 100 per cent. The results reflect the Company's 60 per cent share of equity income up to
December 18, 2012. Refer to Note 23, Acquisitions and Dispositions, for additional information.

Summary of financial information for the equity investees


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Income
Revenues	3,860		4,042		3,920
Operating and other expenses	(3,090	)	(2,989	)	(2,773	)
Net income	717		929		1,009
Net income attributable to TransCanada	257		415		453


at December 31 (millions of Canadian dollars)	2012		2011

Balance Sheet
Current assets	1,593		1,430
Non current assets	12,154		11,550
Current liabilities	(1,187	)	(1,172	)
Non current liabilities	(3,787	)	(3,232	)

INTANGIBLE AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2012

INTANGIBLES AND OTHER ASSETS

Schedule of intangible and other assets


at December 31 (millions of Canadian dollars)	2012	2011

PPAs¹	376	428
Loans and advances²	196	224
Fair value of derivative contracts (Note 21)	187	202
Deferred income tax assets (Note 15)	105	132
Employee post-retirement benefits (Note 20)	11	–
Other	468	480

	1,343	1,466

1: The following amounts related to PPAs are included in Intangible and Other Assets:

Schedule of amounts related to PPAs included in Intangible and Other Assets

2012

2011

at December 31
(millions of Canadian dollars)

Cost

Accumulated
Amortization

Net Book
Value

Cost

Accumulated
Amortization

Net Book
Value

Sheerness

585

273

312

585

234

351

Sundance A

225

161

225

148

810

434

376

810

382

428

Amortization expense for these PPAs was $52 million for the year ended December 31, 2012 (2011 and 2010 – $52 million). The expected annual amortization expense in each
of the next five years is $52 million.

2: As at December 31, 2012, TransCanada held a $236 million (2011 – $265 million) note receivable from the seller of Ravenswood which bears interest at 6.75 per cent and
matures in 2040. The current portion of the note receivable of $40 million (2011 – $41 million) is included in Other Current Assets.

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2012

NOTES PAYABLE

Schedule of notes payable


	2012		2011
(millions of Canadian dollars)	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31	Outstanding December 31	Weighted Average Interest Rate per Annum at December 31

Canadian dollars	803	1.2%	466	1.2%
U.S. dollars (2012 – US$1,480; 2011 – US$1,373)	1,472	0.4%	1,397	0.5%

	2,275		1,863

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2012

ACCOUNTS PAYABLE AND OTHER

Schedule of accounts payable and other


at December 31 (millions of Canadian dollars)	2012	2011

Trade payables	923	696
Fair value of derivative contracts (Note 21)	283	485
Dividends payable	320	305
Regulatory liabilities (Note 8)	100	139
Deferred income tax liabilities (Note 15)	–	81
Other	718	653

	2,344	2,359

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2012

OTHER LONG-TERM LIABILITIES

Schedule of deferred amounts


at December 31 (millions of Canadian dollars)	2012	2011

Employee post-retirement benefit (Note 20)	482	321
Fair value of derivative contracts (Note 21)	186	349
Guarantees (Note 24)	17	118
Asset retirement obligations	72	65
Other	125	76

	882	929

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2012

LONG-TERM DEBT

Schedule of long-term debt


			2012		2011
Outstanding loan amounts (millions of Canadian dollars)		Maturity Dates	Outstanding December 31	Interest Rate¹	Outstanding December 31	Interest Rate¹

TRANSCANADA PIPELINES LIMITED
Debentures
	Canadian dollars	2014 to 2020	874	10.9%	874	10.9%
	U.S. dollars (2012 – US$400; 2011 – US$600)	2021	398	9.9%	610	9.5%
Medium-Term Notes
	Canadian dollars	2013 to 2041	4,549	5.9%	4,549	5.9%
Senior Unsecured Notes
	U.S. dollars (2012 – US$10,126; 2011 – US$8,626)²	2013 to 2040	10,057	5.6%	8,759	6.2%

			15,878		14,792

NOVA GAS TRANSMISSION LTD.
Debentures and Notes
	Canadian dollars	2014 to 2024	382	11.5%	387	11.5%
	U.S. dollars (2012 – US$200; 2011 – US$375)	2023	199	7.9%	381	8.2%
Medium-Term Notes
	Canadian dollars	2025 to 2030	504	7.4%	504	7.4%
	U.S. dollars (2012 and 2011 – US$33)	2026	32	7.5%	33	7.5%

			1,117		1,305

TRANSCANADA PIPELINE USA LTD.
Bank Loan
	U.S. dollars (2012 – nil; 2011 – US$500)		–	–	509	0.6%

ANR PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$432)	2021 to 2025	430	8.9%	438	8.9%

GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$325)	2015 to 2035	323	5.5%	331	5.5%

TC PIPELINES, LP
Unsecured Loan
	U.S. dollars (2012 – US$312; 2011 – US$363)	2017	310	1.5%	369	1.6%
Senior Unsecured Notes
	U.S. dollars (2012 and 2011 – US$350)	2021	348	4.7%	356	4.7%

			658		725

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
	U.S. dollars (2012 – US$354; 2011 – US$373)	2018 to 2030	352	7.8%	379	7.8%

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
	U.S. dollars (2012 – US$27; 2011 – US$30)	2017	27	4.0%	31	4.4%

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes³
	U.S. dollars (2012 – US$129; 2011 – US$147)	2018	128	6.1%	149	6.1%

			18,913		18,659
Less: Current Portion of Long-Term Debt			894		935

			18,019		17,724

1: Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's regulated operations, in which case the weighted average interest rate is presented as
approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.
2: Includes fair value adjustments of $10 million (2011 – $13 million) attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$350 million of debt at December 31, 2012 (2011 – US$350 million).
3: Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Schedule of interest expense


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Interest on long-term debt	1,190		1,154		1,149
Interest on junior subordinated notes	63		63		65
Interest on short-term debt	16		16		15
Capitalized interest	(300	)	(302	)	(587	)
Amortization and other financial charges¹	7		6		59

	976		937		701

1: Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes
in the fair value of derivatives used to manage the Company's exposure to rising interest rates.

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Schedule of provision for income taxes

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2012

INCOME TAXES


year ended December 31 (millions of Canadian dollars)	2012	2011		2010

Current
Canada	167	212		31
Foreign	14	(2	)	(170	)

	181	210		(139	)

Deferred
Canada	69	139		175
Foreign	216	226		351

	285	365		526

Income Tax Expense	466	575		387

Schedule of geographic components of income


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Canada	842	1,176	811
Foreign	1,096	1,109	969

Income before Income Taxes	1,938	2,285	1,780

Schedule of reconciliation of income tax expense


year ended December 31 (millions of Canadian dollars)	2012		2011		2010

Income before Income Taxes	1,938		2,285		1,780
Federal and provincial statutory tax rate	25.0%		26.5%		28.0%
Expected income tax expense	485		605		498
Income tax differential related to regulated operations	41		42		8
Higher/(lower) effective foreign tax rates	1		(5	)	(36	)
Income from equity investments and non-controlling interests	(40	)	(45	)	(40	)
Other	(21	)	(22	)	(43	)

Actual Income Tax Expense	466		575		387

Schedule of deferred income tax assets and liabilities and amounts classified in the consolidated balance sheet


at December 31 (millions of Canadian dollars)	2012	2011

Deferred Income Tax Assets
Operating loss carryforwards	1,024	900
Financial instruments	88	166
Pension and other post-employment benefits	83	42
Deferred amounts	49	49
Other	92	132

	1,336	1,289

Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	3,804	3,609
Equity investments	578	457
Taxes on future revenue requirement	283	295
Unrealized foreign exchange gains on long-term debt	159	133
Other	70	87

	4,894	4,581

Net Deferred Income Tax Liabilities	3,558	3,292

The above deferred tax amounts have been classified in the Consolidated Balance Sheet as follows:


at December 31 (millions of Canadian dollars)	2012	2011

Deferred Income Tax Assets
Other current assets (Note 5)	290	248
Intangible and other assets (Note 10)	105	132

	395	380

Deferred Income Tax Liabilities
Accounts payable and other (Note 12)	–	81
Deferred income taxes	3,953	3,591

	3,953	3,672

Net Deferred Income Tax Liabilities	3,558	3,292

Schedule of reconciliation of the annual changes in the total unrecognized tax benefit


at December 31 (millions of Canadian dollars)	2012		2011		2010

Unrecognized tax benefits at beginning of year	52		62		55
Gross increases – tax positions in prior years	2		9		7
Gross decreases – tax positions in prior years	(6	)	(7	)	(1	)
Gross increases – tax positions in current year	9		11		9
Settlements	–		–		(7	)
Lapses of statute of limitations	(8	)	(23	)	(1	)

Unrecognized tax benefits at end of year	49		52		62

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2012

JUNIOR SUBORDINATED NOTES

Schedule of junior subordinated notes


			2012		2011
Outstanding loan amount (millions of Canadian dollars)		Maturity Date	Outstanding December 31	Effective Interest Rate	Outstanding December 31	Effective Interest Rate

TRANSCANADA PIPELINES LIMITED
	U.S. dollars (2012 and 2011 – US$1,000)	2067	994	6.5%	1,016	6.5%

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2012

NON-CONTROLLING INTERESTS

Schedule of the Company's non-controlling interests included in the Consolidated Balance Sheet


at December 31 (millions of Canadian dollars)	2012	2011

Non-controlling interest in TC PipeLines, LP¹	953	997
Preferred shares of TCPL	389	389
Non-controlling interest in Portland²	83	79

	1,425	1,465

Schedule of the Company's non-controlling interests included in the Consolidated Statement of Income


year ended December 31 (millions of Canadian dollars)	2012	2011	2010

Non-controlling interest in TC PipeLines, LP¹	91	101	87
Preferred share dividends of TCPL	22	22	22
Non-controlling interest in Portland²	5	6	6

	118	129	115

1: Effective May 3, 2011, the non-controlling interest in TC PipeLines, LP increased from 61.8 per cent to 66.7 per cent due to the issuance of equity to non-controlling
interests in TC PipeLines, LP associated with the sale of 25 per cent interests in GTN LLC and Bison LLC pipelines from TransCanada to TC PipeLines, LP. The
non-controlling interest in TC PipeLines, LP from January 1, 2010 to May 3, 2011 was 61.8 per cent.
2: The non-controlling interests in Portland as at December 31, 2012 represented the 38.3 per cent interest not owned by TransCanada (2011 and 2010 – 38.3 per cent).

Schedule of Preferred Shares of Subsidiary


at December 31	Number of Shares	Dividend Rate per Share	Redemption Price per Share	2012	2011

	(thousands)			(millions of Canadian dollars)	(millions of Canadian dollars)
Cumulative First Preferred Shares of Subsidiary
Series U	4,000	$2.80	$50.00	195	195
Series Y	4,000	$2.80	$50.00	194	194

				389	389

Tabular disclosure of preferred units of master limited partnerships that have priority over limited partner units in areas including liquidation, redemption, conversion, tax status of distribution or sharing in distributions. This schedule ordinarily includes a description of the preferred units that details various rights including redemption, conversion, liquidation, and sharing in distributions; capital contributed by preferred partners; number of preferred units authorized to be issued, issued, and outstanding; aggregate cumulative cash distributions made to the preferred partners; aggregate cumulative net income earned by the preferred partners; capital account balance of the preferred partners.

Schedule of common shares

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2012

COMMON SHARES


		Number of Shares	Amount

		(thousands)	(millions of Canadian dollars)
Outstanding at January 1, 2010		684,359	11,338
	Dividend reinvestment and share purchase plan	10,670	378
	Exercise of options	1,201	29

Outstanding at December 31, 2010		696,230	11,745
	Dividend reinvestment and share purchase plan	5,371	202
	Exercise of options	2,260	64

Outstanding at December 31, 2011		703,861	12,011
	Exercise of options	1,600	58

Outstanding at December 31, 2012		705,461	12,069

Schedule of stock options activity


	Number of Options		Weighted Average Exercise Prices	Options Exercisable

	(thousands)			(thousands)
Outstanding at January 1, 2010	8,274		$30.56	6,212
Granted	1,367		$35.32
Exercised	(1,201	)	$22.04
Forfeited	(34	)	$27.35

Outstanding at December 31, 2010	8,406		$32.57	6,458
Granted	970		$38.02
Exercised	(2,260	)	$25.86
Forfeited	(16	)	$35.83

Outstanding at December 31, 2011	7,100		$35.44	5,165
Granted	1,978		$42.03
Exercised	(1,600	)	$33.13
Forfeited	(44	)	$36.55

Outstanding at December 31, 2012	7,434		$37.69	4,588

Schedule of stock options outstanding and exercisable by the range of exercise price


at December 31, 2012	Options Outstanding			Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life

	(thousands)		(years)	(thousands)		(years)
$30.10 to $31.97	1,093	$31.95	3.2	1,093	$31.95	3.2
$32.40 to $35.08	1,387	$34.64	4.0	1,160	$34.55	4.0
$35.23 to $37.93	1,202	$37.52	5.0	556	$37.22	4.9
$38.10 to $39.75	1,750	$38.83	1.7	1,750	$38.83	1.7
$41.65 to $45.29	2,002	$42.03	6.1	29	$41.87	5.9

	7,434	$37.69	3.9	4,588	$35.93	2.7

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2012

PREFERRED SHARES

Schedule of preferred shares


at December 31	Number of Shares Authorized and Outstanding	Dividend Rate per Share	Redemption Price per Share	2012	2011

	(thousands)			(millions of Canadian dollars)¹	(millions of Canadian dollars)¹
Cumulative First Preferred Shares
Series 1	22,000	$1.15	$25.00	539	539
Series 3	14,000	$1.00	$25.00	343	343
Series 5	14,000	$1.10	$25.00	342	342

				1,224	1,224

1: Net of underwriting commissions and deferred income taxes.

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 150
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29
-Article 5

Schedule of change in benefit obligations, change in plan assets, and funded status

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2012

Employee post-retirement benefits


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Change in Benefit Obligation¹
Benefit obligation – beginning of year	1,836		1,622		170		159
Service cost	66		54		2		2
Interest cost	94		91		8		9
Employee contributions	4		4		1		1
Benefits paid	(79	)	(71	)	(9	)	(9	)
Actuarial loss	227		131		16		7
Foreign exchange rate changes	(6	)	5		(2	)	1

Benefit obligation – end of year	2,142		1,836		186		170

Change in Plan Assets
Plan assets at fair value – beginning of year	1,656		1,636		29		29
Actual return on plan assets	165		21		4		–
Employer contributions	83		62		7		8
Employee contributions	4		4		1		1
Benefits paid	(79	)	(71	)	(9	)	(9	)
Foreign exchange rate changes	(4	)	4		–		–

Plan assets at fair value – end of year	1,825		1,656		32		29

Funded Status – Plan Deficit	(317	)	(180	)	(154	)	(141	)

1: The benefit obligation for the Company's pension benefit plan represents the projected benefit obligation. The benefit obligation for the Company's other post-retirement
benefit plans represents the accumulated post-retirement benefit obligation.

Schedule of amounts recognized in the Company's Balance Sheet for its DB plans and other post-retirement benefits plans


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Intangible and Other Assets (Note 10)	–		–		11		–
Other Long-Term Liabilities (Note 13)	(317	)	(180	)	(165	)	(141	)

	(317	)	(180	)	(154	)	(141	)

Schedule of benefit obligations in excess of fair value of plan assets


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2012		2011

Benefit obligation	(2,142	)	(1,836	)	(186	)	(170	)
Plan assets at fair value	1,825		1,656		32		29

Funded Status – Deficit	(317	)	(180	)	(154	)	(141	)

Schedule of accumulated benefit obligations in excess of fair value of plan assets for all DB Plans


at December 31 (millions of Canadian dollars)	2012		2011

Accumulated benefit obligation	(1,966	)	(1,691	)
Plan assets at fair value	1,825		1,656

Funded Status – Deficit	(141	)	(35	)

Schedule of accumulated benefit obligations in excess of fair value of plan assets for plans not fully funded


at December 31 (millions of Canadian dollars)	2012		2011

Accumulated benefit obligation	(1,966	)	(446	)
Plan assets at fair value	1,825		391

Funded Status – Deficit	(141	)	(55	)

Schedule of the Company's pension plans weighted average asset allocations and target allocations by asset category


	Percentage of Plan Assets		Target Allocations
at December 31	2012	2011	2012

Debt securities	36%	39%	35% to 60%
Equity securities	64%	61%	40% to 65%

	100%	100%

Schedule of plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into three categories based on a fair value hierarchy

at December 31
(millions of

Quoted Prices in
Active Markets
(Level I)

Significant Other Observable Inputs
(Level II)

Significant Unobservable Inputs
(Level III)

Total

Percentage of
Total Portfolio

Canadian dollars)

2012

2011

2012

2011

2012

2011

2012

2011

2012

2011

Asset Category

Cash and cash equivalents

–

Equity Securities:

Canadian

400

374

113

–

513

469

28%

28%

U.S.

309

251

–

347

306

19%

18%

International

263

231

–

294

256

16%

15%

Global

–

Fixed Income Securities:

Canadian Bonds:

Federal

–

314

303

–

314

303

17%

18%

Provincial

–

161

158

–

161

158

Municipal

–

Corporate

–

U.S. Bonds:

State

–

Corporate

–

International:

Corporate

–

Mortgage Backed

–

Other Investments:

Private Equity Funds

–

757

675

1,081

990

1,857

1,685

100%

100%

Schedule of the net change in the Level III fair value category


(millions of Canadian dollars, pre-tax)	Private Equity Funds

Balance at December 31, 2010	21
Realized and unrealized losses	(2	)
Purchases and sales	1

Balance at December 31, 2011	20

Realized and unrealized losses	(1	)

Balance at December 31, 2012	19

Schedule of estimated future benefit payments, which reflect expected future service


(millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits

2013	90	9
2014	96	9
2015	101	10
2016	107	10
2017	111	11
2018 to 2022	636	58

Schedule of significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations


	Pension Benefit Plans		Other Post-Retirement Benefit Plans
at December 31	2012	2011	2012	2011

Discount rate	4.35%	5.05%	4.35%	5.10%
Rate of compensation increase	3.15%	3.15%

Schedule of significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs

Pension
Benefit Plans

Other
Post-Retirement
Benefit Plans

year ended December 31

2012

2011

2010

2012

2011

2010

Discount rate

5.05%

5.55%

6.00%

5.10%

5.60%

6.00%

Expected long-term rate of return on plan assets

6.70%

6.95%

6.40%

6.40%

7.80%

Rate of compensation increase

3.15%

3.10%

3.20%

Schedule of effects of a one per cent change in assumed health care cost trend rates


(millions of Canadian dollars)	Increase	Decrease

Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	17	(14	)

Schedule of the Company's net benefit cost


year ended December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian dollars)	2012		2011		2010		2012		2011		2010

Service cost	66		54		50		2		2		2
Interest cost	94		91		89		8		9		9
Expected return on plan assets	(113	)	(114	)	(108	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	18		10		5		1		1		1
Amortization of past service cost	2		2		2		1		–		–
Amortization of regulatory asset	19		12		5		1		1		1
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2

Net Benefit Cost Recognized	86		55		43		13		13		13

Schedule of the pre-tax amounts recognized in AOCI


at December 31	2012		2011		2010
(millions of Canadian dollars)	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits

Net loss	362	33	282	29	179	24
Prior service cost	5	2	7	2	9	2

	367	35	289	31	188	26

Schedule of the pre-tax amounts recognized in OCI


at December 31	2012				2011				2010
(millions of Canadian dollars)	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits

Amortization of net loss from AOCI to OCI	(19	)	(1	)	(10	)	(1	)	(5	)	(1	)
Amortization of prior service costs from AOCI to OCI	(2	)	–		(2	)	–		(2	)	–
Funded status adjustment	99		5		113		6		15		4

	78		4		101		5		8		3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2012

Derivative financial instruments

Schedule of the carrying and fair values of non-derivative financial instruments


	2012		2011
at December 31 (millions of Canadian dollars)	Carrying Amount¹	Fair Value²	Carrying Amount¹	Fair Value²

Financial Assets
Cash and cash equivalents	551	551	654	654
Accounts receivable and other³	1,288	1,337	1,359	1,403
Available for sale assets³	44	44	23	23

	1,883	1,932	2,036	2,080

Financial Liabilities⁴
Notes payable	2,275	2,275	1,863	1,863
Accounts payable and other long-term liabilities⁵	1,535	1,535	1,329	1,329
Accrued interest	368	368	365	365
Long-term debt	18,913	24,573	18,659	23,757
Junior subordinated notes	994	1,054	1,016	1,027

	24,085	29,805	23,232	28,341

1: Recorded at amortized cost, except for $350 million (2011 – $350 million) of Long-Term Debt that is attributed to hedged risk and recorded at fair value. This debt, which is recorded at fair value on a recurring
basis, is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.
2: The fair value measurement of financial assets and liabilities recorded at amortized cost for which the fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the
income approach based on interest rates from external data service providers.
3: At December 31, 2012, the Consolidated Balance Sheet included financial assets of $1.1 billion (2011 – $1.1 billion) in Accounts Receivable, $40 million (2011 – $41 million)
in Other Current Assets and $240 million (2011 – $247 million) in Intangible and Other Assets.
4: Consolidated Net Income in 2012 included losses of $10 million (2011 – losses of $13 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest
rate swap fair value hedging relationships on US$350 million of debt at December 31, 2012 (2011 – US$350 million). There were no other unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
5: At December 31, 2012, the Consolidated Balance Sheet included financial liabilities of $1.5 billion (2011 – $1.2 billion) in Accounts Payable and $38 million (2011 – $137 million)
in Other Long-Term Liabilities.

Schedule of the remaining contractual maturities for the non-derivative financial liabilities, including both the principal and interest cash flows


	Payments Due by Period
(millions of Canadian dollars)	Total	2013	2014 and 2015	2016 and 2017	2018 and Thereafter

Notes payable	2,275	2,275	–	–	–
Long-term debt	18,913	894	2,531	1,769	13,719
Junior subordinated notes	994	–	–	–	994

	22,182	3,169	2,531	1,769	14,713

1: The anticipated timing of settlement of derivative contracts is presented in the Derivatives Instrument Summary in this note.

Interest Payments on Financial Liabilities


	Payments Due by Period
(millions of Canadian dollars)	Total	2013	2014 and 2015	2016 and 2017	2018 and Thereafter

Long-term debt	15,377	1,154	2,125	1,908	10,190
Junior subordinated notes	3,443	63	126	126	3,128

	18,820	1,217	2,251	2,034	13,318

Schedule of fair value of the derivative financial instruments in the Company's Balance Sheet


at December 31 (millions of Canadian dollars)	2012		2011

Current
Other current assets (Note 5)	259		361
Accounts payable and other (Note 12)	(283	)	(485	)
Long Term
Intangible and other assets (Note 10)	187		202
Other long-term liabilities (Note 13)	(186	)	(349	)

Schedule of components of OCI related to derivates in cash flow hedging relationships

Cash Flow Hedges¹

Power

Natural Gas

Foreign Exchange

Interest

year ended December 31
(millions of Canadian dollars, pre-tax)

2012

2011

2012

2011

2012

2011

2012

2011

Change in fair value of derivative instruments recognized in OCI (effective portion)

(263

)

(21

)

(59

)

–

)

Reclassification of gains and losses on derivative instruments from AOCI to Net Income (effective portion)

147

100

–

Gains and losses on derivative instruments recognized in earnings (ineffective portion)

–

1: No amounts have been excluded from the assessment of hedge effectiveness.

Schedule of fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions


December 31 (millions of Canadian dollars,		Quoted Prices in Active Markets (Level I)				Significant Other Observable Inputs (Level II)				Significant Unobservable Inputs (Level III)				Total
pre-tax)		2012		2011		2012		2011		2012		2011		2012		2011

Derivative Instrument Assets:
	Interest rate contracts	–		–		24		35		–		–		24		35
	Foreign exchange contracts	–		–		119		142		–		–		119		142
	Power commodity contracts	–		–		213		201		2		–		215		201
	Gas commodity contracts	75		124		13		55		–		–		88		179
Derivative Instrument Liabilities:
	Interest rate contracts	–		–		(14	)	(23	)	–		–		(14	)	(23	)
	Foreign exchange contracts	–		–		(76	)	(102	)	–		–		(76	)	(102	)
	Power commodity contracts	–		–		(269	)	(454	)	(4	)	(15	)	(273	)	(469	)
	Gas commodity contracts	(95	)	(208	)	(11	)	(26	)	–		–		(106	)	(234	)
Non-Derivative Financial Instruments:
	Available-for-sale assets	44		23		–		–		–		–		44		23

		24		(61	)	(1	)	(172	)	(2	)	(15	)	21		(248	)

Schedule of net change in the Level III fair value category


(millions of Canadian dollars, pre-tax)	Derivatives^1,2

Balance at December 31, 2010	(8	)
New contracts	1
Settlements	2
Transfers out of Level III	3
Total losses included in OCI	(13	)

Balance at December 31, 2011	(15	)

Settlements	(1	)
Transfers out of Level III	(21	)
Total gains included in Net Income	11
Total gains included in OCI	24

Balance at December 31, 2012	(2	)

1: The fair value of derivative assets and liabilities is presented on a net basis.
2: At December 31, 2012, there were unrealized gains included in Net Income attributable to derivatives that were still held at the reporting date of $1 million (2011 – nil).

Derivative financial instrument, excluding net investment hedges

Derivative financial instruments

Schedule of fair values and notional or principal amounts for the derivatives


at December 31			2012
(all amounts in Canadian millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Instruments Held for Trading¹
Fair Values²
	Assets		$139		$88		$1		$14
	Liabilities		$(176	)	$(104	)	$(2	)	$(14	)
Notional Values
	Volumes³
		Purchases	31,135		83		–		–
		Sales	31,066		65		–		–
	Canadian dollars		–		–		–		620
	U.S. dollars		–		–		US 1,408		US 200
	Cross-currency		–		–		–		–
Net unrealized (losses)/gains in the year⁴			$(30	)	$2		$(1	)	$–
Net realized gains/(losses) in the year⁴			$5		$(10	)	$26		$–
Maturity dates			2013-2017		2013-2016		2013		2013-2016
Derivative Instruments in Hedging Relationships^5,6
Fair Values²
	Assets		$76		$–		$–		$10
	Liabilities		$(97	)	$(2	)	$(38	)	$–
Notional Values
	Volumes³
		Purchases	15,184		1		–		–
		Sales	7,200		–		–		–
	U.S. dollars		–		–		US 12		US 350
	Cross-currency		–		–		136/US 100		–
Net realized (losses)/gains in the year⁴			$(130	)	$(23	)	$–		$7
Maturity dates			2013-2018		2013		2013-2014		2013-2015

1: All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been
designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
2: Fair values equal carrying values.
3: Volumes for power and natural gas derivatives are in GWh and billion cubic feet (Bcf), respectively.
4: Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and losses on interest rate
and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of the change in fair value of derivative
instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.
5: All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $10 million and a notional amount of
US$350 million. In 2012, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2012, the Company did not record any amounts in Net Income related to
ineffectiveness for fair value hedges.
6: In 2012, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.


at December 31			2011
(all amounts in Canadian millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest

Derivative Instruments Held for Trading¹
Fair Values²
	Assets		$185		$176		$3		$22
	Liabilities		$(192	)	$(212	)	$(14	)	$(22	)
Notional Values
	Volumes³
		Purchases	21,905		103		–		–
		Sales	21,334		82		–		–
	Canadian dollars		–		–		–		684
	U.S. dollars		–		–		US 1,269		US 250
	Cross-currency		–		–		47/US 37		–
Net unrealized (losses)/gains in the year⁴			$(2	)	$(50	)	$(4	)	$1
Net realized gains/(losses) in the year⁴			$42		$(74	)	$10		$1
Maturity dates			2012-2016		2012-2016		2012		2012-2016
Derivative Instruments in Hedging Relationships^5,6
Fair Values²
	Assets		$16		$3		$–		$13
	Liabilities		$(277	)	$(22	)	$(38	)	$(1	)
Notional Values
	Volumes³
		Purchases	17,188		8		–		–
		Sales	8,061		–		–		–
	U.S. dollars		–		–		US 73		US 600
	Cross-currency		–		–		136/US 100		–
Net realized losses in the year⁴			$(165	)	$(17	)	$–		$(16	)
Maturity dates			2012-2017		2012-2013		2012-2014		2012-2015

1: All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company's risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
2: Fair values equal carrying values.
3: Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
4: Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in Revenues. Realized and unrealized gains and
losses on interest rate and foreign exchange derivative instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion
of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
5: All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $13 million and a
notional amount of US$350 million. In 2011, net realized gains on fair value hedges were $7 million and were included in Interest Expense. In 2011, the Company did not record any amounts

in Net Income related to ineffectiveness for fair value hedges.
6: In 2011, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Designated as a net investment hedge

Derivative financial instruments

Schedule of fair values and notional or principal amounts for the derivatives


	2012		2011
at December 31 (millions of Canadian dollars)	Fair Value¹	Notional or Principal Amount	Fair Value¹		Notional or Principal Amount

U.S. dollar cross-currency swaps (maturing 2013 to 2019)²	82	US 3,800	93		US 3,850
U.S. dollar forward foreign exchange contracts (maturing 2013)	–	US 250	(4	)	US 725

	82	US 4,050	89		US 4,575

1: Fair values equal carrying values.
2: Net Income in 2012 included net realized gains of $30 million (2011 – gains of $27 million) related to the interest component of cross-currency swap settlements.

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2012

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital


year ended December 31 (millions of Canadian dollars)	2012	2011		2010

Decrease/(increase) in accounts receivable	67	(15	)	(286	)
Decrease in inventories	27	3		25
Decrease/(increase) in other current assets	66	(27	)	(76	)
Increase in accounts payable and other	127	266		60
Increase/(decrease) in accrued interest	–	8		(8	)

Decrease/(Increase) in Operating Working Capital	287	235		(285	)

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2012

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Schedule of future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment


year ended December 31 (millions of Canadian dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases		Net Payments

2013	82	(8	)	74
2014	80	(8	)	72
2015	80	(7	)	73
2016	81	(4	)	77
2017	80	(2	)	78
2018 and thereafter	374	(1	)	373

	777	(30	)	747

Schedule of generating capacities and expiry dates of the PPAs


	Megawatts	Expiry Date

Sundance A	560	December 31, 2017
Sundance B¹	353	December 31, 2020
Sheerness	756	December 31, 2020

DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)		12 Months Ended
DESCRIPTION OF TRANSCANADA'S BUSINESS (Details)	Dec. 15, 2011 item MW	Dec. 31, 2012	Dec. 31, 2012 mi	Dec. 31, 2012 km	Dec. 31, 2012 MW	Dec. 31, 2012 item	Dec. 31, 2011	May 03, 2011	Dec. 31, 2010
DESCRIPTION OF TRANSCANADA'S BUSINESS
Number of business segments in which the entity operates \| item						3
Ontario solar projects
Description of business
Number of Ontario solar projects that the entity has agreed to purchase \| item	9
Combined capacity of Ontario solar project (in Megawatts)	86
Sundance A
Description of business
Power generating capacities of facilities purchased under PPA (in Megawatts)					560
Sundance B
Description of business
Power generating capacities of facilities purchased under PPA (in Megawatts)					353
Sheerness
Description of business
Power generating capacities of facilities purchased under PPA (in Megawatts)					756
TC PipeLines, LP
Description of business
Direct ownership interest (as a percent)		33.30%	33.30%	33.30%	33.30%	33.30%	33.30%	38.20%	38.20%
ASTC Power Partnership
Description of business
Ownership interest (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%
Natural Gas Pipelines \| TC PipeLines, LP
Description of business
Direct ownership interest (as a percent)		33.30%	33.30%	33.30%	33.30%	33.30%
Natural Gas Pipelines \| Ontario Power Authority
Description of business
Capacity of plant under a contract to develop, own and operate (in Megawatts)					900
Natural Gas Pipelines \| TQM
Description of business
Ownership interest (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%
Natural Gas Pipelines \| Northern Border
Description of business
Ownership interest (as a percent)		16.70%	16.70%	16.70%	16.70%	16.70%	16.70%		19.10%
Natural Gas Pipelines \| Northern Border \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%
Natural Gas Pipelines \| Iroquois
Description of business
Ownership interest (as a percent)		44.50%	44.50%	44.50%	44.50%	44.50%
Natural Gas Pipelines \| Great Lakes
Description of business
Direct ownership interest (as a percent)		53.60%	53.60%	53.60%	53.60%	53.60%
Combined effective ownership interest (as a percent)		69.00%
Natural Gas Pipelines \| Great Lakes \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		46.40%	46.40%	46.40%	46.40%	46.40%
Natural Gas Pipelines \| GTN
Description of business
Direct ownership interest (as a percent)		75.00%	75.00%	75.00%	75.00%	75.00%
Combined effective ownership interest (as a percent)		83.30%
Natural Gas Pipelines \| GTN \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		25.00%	25.00%	25.00%	25.00%	25.00%
Natural Gas Pipelines \| Bison
Description of business
Direct ownership interest (as a percent)		75.00%	75.00%	75.00%	75.00%	75.00%
Combined effective ownership interest (as a percent)		83.30%
Natural Gas Pipelines \| Bison \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		25.00%	25.00%	25.00%	25.00%	25.00%
Natural Gas Pipelines \| Portland
Description of business
Direct ownership interest (as a percent)		61.70%	61.70%	61.70%	61.70%	61.70%
Natural Gas Pipelines \| North Baja
Description of business
Combined effective ownership interest (as a percent)		33.30%
Natural Gas Pipelines \| North Baja \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		100.00%
Natural Gas Pipelines \| Tuscarora
Description of business
Combined effective ownership interest (as a percent)		33.30%
Natural Gas Pipelines \| Tuscarora \| TC PipeLines, LP
Description of business
Ownership interest (as a percent)		100.00%
Natural Gas Pipelines \| TransGas
Description of business
Direct ownership interest (as a percent)		46.50%	46.50%	46.50%	46.50%	46.50%
Natural Gas Pipelines \| Gas Pacifico and INNERGY
Description of business
Direct ownership interest (as a percent)		30.00%	30.00%	30.00%	30.00%	30.00%
Oil Pipelines
Description of business
Length of pipeline system			54	90
Length of new pipeline under regulatory approval			1,179	1,897
Oil Pipelines \| Phoenix Energy Holdings Limited
Description of business
Length of pipeline system			300	500
Energy \| Sundance A
Description of business
Interest purchased (as a percent)		100.00%
Power generating capacities of facilities purchased under PPA (in Megawatts)					560
Energy \| Sundance B
Description of business
Power generating capacities of facilities purchased under PPA (in Megawatts)					706
Energy \| Sheerness
Description of business
Interest purchased (as a percent)		100.00%
Power generating capacities of facilities purchased under PPA (in Megawatts)					756
Energy \| Bruce A
Description of business
Ownership interest (as a percent)		48.90%	48.90%	48.90%	48.90%	48.90%
Energy \| Bruce B
Description of business
Ownership interest (as a percent)		31.60%	31.60%	31.60%	31.60%	31.60%
Energy \| Portlands Energy
Description of business
Ownership interest (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%
Energy \| ASTC Power Partnership
Description of business
Ownership interest (as a percent)		50.00%	50.00%	50.00%	50.00%	50.00%
Energy \| Cartier Wind
Description of business
Direct ownership interest (as a percent)		62.00%	62.00%	62.00%	62.00%	62.00%

ACCOUNTING POLICIES (Details)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2012 item
Annual review for goodwill impairment
Number of levels below operating segments level considered for measuring reporting unit level	1
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Natural Gas Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	1.00%
Natural Gas Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	6.00%
Natural Gas Pipelines \| Compression \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	1.00%
Natural Gas Pipelines \| Compression \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	6.00%
Oil Pipelines \| Pipeline \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Oil Pipelines \| Pipeline \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.50%
Oil Pipelines \| Pumping equipment \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Oil Pipelines \| Pumping equipment \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.50%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	2.00%
Energy \| Power generation and natural gas storage plant, equipment and structures \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	20.00%
Corporate \| Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	3.00%
Corporate \| Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis (as a percent)	20.00%

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segmented information
Revenues	$ 8,007	$ 7,839	$ 6,852
Income/(Loss) from Equity investments	257	415	453
Plant operating costs and other	(2,577)	(2,358)	(2,069)
Commodity purchases resold	(1,049)	(991)	(1,178)
Property taxes	(434)	(410)	(365)
Depreciation and amortization	(1,375)	(1,328)	(1,160)
Valuation provision			(146)
Operating income (loss)	2,829	3,167	2,387
Interest expense	(976)	(937)	(701)
Interest income and other	85	55	94
Income before Income Taxes	1,938	2,285	1,780
Income tax expense	(466)	(575)	(387)
Net Income	1,472	1,710	1,393
Net Income Attributable to Non-Controlling Interests	(118)	(129)	(115)
Net Income Attributable to Controlling Interests	1,354	1,581	1,278
Preferred Share Dividends	(55)	(55)	(45)
Net Income Attributable to Common Shares	1,299	1,526	1,233
TOTAL ASSETS
Total Assets	48,333	47,338
GEOGRAPHIC INFORMATION
Revenues	8,007	7,839	6,852
Plant, Property and Equipment	33,713	32,467
CAPITAL EXPENDITURES
Capital Expenditures	2,595	2,513	4,376
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	18,054	17,552
Canada - domestic
Segmented information
Revenues	3,527	3,929	3,178
GEOGRAPHIC INFORMATION
Revenues	3,527	3,929	3,178
Canada - export
Segmented information
Revenues	1,121	1,087	838
GEOGRAPHIC INFORMATION
Revenues	1,121	1,087	838
United States
Segmented information
Revenues	3,252	2,752	2,796
GEOGRAPHIC INFORMATION
Revenues	3,252	2,752	2,796
Plant, Property and Equipment	14,904	14,388
Mexico
Segmented information
Revenues	107	71	40
GEOGRAPHIC INFORMATION
Revenues	107	71	40
Plant, Property and Equipment	755	527
Natural Gas Pipelines
Segmented information
Revenues	4,264	4,244	4,122
Income/(Loss) from Equity investments	157	159	153
Plant operating costs and other	(1,365)	(1,221)	(1,165)
Property taxes	(315)	(307)	(294)
Depreciation and amortization	(933)	(923)	(913)
Valuation provision			(146)
Operating income (loss)	1,808	1,952	1,757
TOTAL ASSETS
Total Assets	23,210	23,161
GEOGRAPHIC INFORMATION
Revenues	4,264	4,244	4,122
Plant, Property and Equipment	17,548	17,202
CAPITAL EXPENDITURES
Capital Expenditures	1,389	917	1,192
Oil Pipelines
Segmented information
Revenues	1,039	827
Plant operating costs and other	(296)	(209)
Property taxes	(45)	(31)
Depreciation and amortization	(145)	(130)
Operating income (loss)	553	457
TOTAL ASSETS
Total Assets	10,485	9,440
GEOGRAPHIC INFORMATION
Revenues	1,039	827
Plant, Property and Equipment	10,232	9,254
CAPITAL EXPENDITURES
Capital Expenditures	1,145	1,204	2,696
Energy
Segmented information
Revenues	2,704	2,768	2,730
Income/(Loss) from Equity investments	100	256	300
Plant operating costs and other	(819)	(842)	(805)
Commodity purchases resold	(1,049)	(991)	(1,178)
Property taxes	(74)	(72)	(71)
Depreciation and amortization	(283)	(261)	(247)
Operating income (loss)	579	858	729
TOTAL ASSETS
Total Assets	13,157	13,269
GEOGRAPHIC INFORMATION
Revenues	2,704	2,768	2,730
Plant, Property and Equipment	5,833	5,933
CAPITAL EXPENDITURES
Capital Expenditures	24	384	473
Corporate
Segmented information
Plant operating costs and other	(97)	(86)	(99)
Depreciation and amortization	(14)	(14)
Operating income (loss)	(111)	(100)	(99)
TOTAL ASSETS
Total Assets	1,481	1,468
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	100	78
CAPITAL EXPENDITURES
Capital Expenditures	$ 37	$ 8	$ 15

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
OTHER CURRENT ASSETS
Fair value of derivative contracts (Note 21)	$ 259	$ 361
Deferred income tax assets (Note 15)	290	248
Regulatory assets (Note 8)	178	178
Other	270	327
Total other current assets	$ 997	$ 1,114

Amount after allocation of valuation allowances of deferred tax asset attributable to deductible temporary differences and carryforwards expected to be realized or consumed within one year or operating cycle, if longer.

Fair values as of the balance sheet date for all assets resulting from contracts that meet the criteria of being accounted for as derivative instruments and which are expected to be converted into cash or otherwise disposed of within a year or the normal operating cycle, if longer, net of the effects of master netting arrangements.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13495-108611

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 45
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6945355&loc=d3e41228-113958

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6945355&loc=d3e41271-113958

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Current Assets
-URI http://asc.fasb.org/extlink&oid=6509628

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FIN39-1
-Paragraph 10A, 10B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section A
-Paragraph 4
-Chapter 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 4, 17
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 18, 2012
Plant, property and equipment
Cost	$ 50,253	$ 47,873
Accumulated Depreciation	16,540	15,406
Net Book Value	33,713	32,467
Amount capitalized relating to the equity portion of AFUDC	300	302	$ 587
Revenues recognized through the sale of electricity	2,704	2,768	2,730
Natural Gas Pipelines
Plant, property and equipment
Cost	32,330	31,200
Accumulated Depreciation	14,782	13,998
Net Book Value	17,548	17,202
Amount capitalized relating to the equity portion of AFUDC	32	23
Natural Gas Pipelines \| Pipeline \| Mexico
Plant, property and equipment
Cost	536	547
Accumulated Depreciation	59	39
Net Book Value	477	508
Natural Gas Pipelines \| Canadian Mainline
Plant, property and equipment
Cost	12,725	12,558
Accumulated Depreciation	7,254	6,898
Net Book Value	5,471	5,660
Natural Gas Pipelines \| Canadian Mainline \| Pipeline
Plant, property and equipment
Cost	8,801	8,785
Accumulated Depreciation	5,192	4,958
Net Book Value	3,609	3,827
Natural Gas Pipelines \| Canadian Mainline \| Compression
Plant, property and equipment
Cost	3,370	3,362
Accumulated Depreciation	1,880	1,765
Net Book Value	1,490	1,597
Natural Gas Pipelines \| Canadian Mainline \| Metering and other
Plant, property and equipment
Cost	391	383
Accumulated Depreciation	182	175
Net Book Value	209	208
Natural Gas Pipelines \| Canadian Mainline \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	12,562	12,530
Accumulated Depreciation	7,254	6,898
Net Book Value	5,308	5,632
Natural Gas Pipelines \| Canadian Mainline \| Under construction
Plant, property and equipment
Cost	163	28
Net Book Value	163	28
Natural Gas Pipelines \| Alberta System
Plant, property and equipment
Cost	10,520	9,778
Accumulated Depreciation	4,818	4,580
Net Book Value	5,702	5,198
Natural Gas Pipelines \| Alberta System \| Pipeline
Plant, property and equipment
Cost	7,214	6,701
Accumulated Depreciation	3,221	3,062
Net Book Value	3,993	3,639
Natural Gas Pipelines \| Alberta System \| Compression
Plant, property and equipment
Cost	1,885	1,778
Accumulated Depreciation	1,177	1,109
Net Book Value	708	669
Natural Gas Pipelines \| Alberta System \| Metering and other
Plant, property and equipment
Cost	958	931
Accumulated Depreciation	420	409
Net Book Value	538	522
Natural Gas Pipelines \| Alberta System \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	10,057	9,410
Accumulated Depreciation	4,818	4,580
Net Book Value	5,239	4,830
Natural Gas Pipelines \| Alberta System \| Under construction
Plant, property and equipment
Cost	463	368
Net Book Value	463	368
Natural Gas Pipelines \| ANR
Plant, property and equipment
Cost	1,961	1,912
Accumulated Depreciation	202	178
Net Book Value	1,759	1,734
Natural Gas Pipelines \| ANR \| Pipeline
Plant, property and equipment
Cost	864	858
Accumulated Depreciation	49	47
Net Book Value	815	811
Natural Gas Pipelines \| ANR \| Compression
Plant, property and equipment
Cost	514	510
Accumulated Depreciation	72	72
Net Book Value	442	438
Natural Gas Pipelines \| ANR \| Metering and other
Plant, property and equipment
Cost	520	524
Accumulated Depreciation	81	59
Net Book Value	439	465
Natural Gas Pipelines \| ANR \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	1,898	1,892
Accumulated Depreciation	202	178
Net Book Value	1,696	1,714
Natural Gas Pipelines \| ANR \| Under construction
Plant, property and equipment
Cost	63	20
Net Book Value	63	20
Natural Gas Pipelines \| Other Natural Gas Pipelines
Plant, property and equipment
Cost	7,124	6,952
Accumulated Depreciation	2,508	2,342
Net Book Value	4,616	4,610
Natural Gas Pipelines \| Other Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	6,827	6,919
Accumulated Depreciation	2,508	2,342
Net Book Value	4,319	4,577
Natural Gas Pipelines \| Other Natural Gas Pipelines \| Under construction
Plant, property and equipment
Cost	297	33
Net Book Value	297	33
Natural Gas Pipelines \| GTN \| Pipeline
Plant, property and equipment
Cost	1,565	1,589
Accumulated Depreciation	411	370
Net Book Value	1,154	1,219
Natural Gas Pipelines \| Great Lakes \| Pipeline
Plant, property and equipment
Cost	1,544	1,577
Accumulated Depreciation	750	741
Net Book Value	794	836
Natural Gas Pipelines \| Foothills \| Pipeline
Plant, property and equipment
Cost	1,634	1,630
Accumulated Depreciation	1,062	1,005
Net Book Value	572	625
Natural Gas Pipelines \| Other \| Pipeline
Plant, property and equipment
Cost	1,548	1,576
Accumulated Depreciation	226	187
Net Book Value	1,322	1,389
Oil Pipelines
Plant, property and equipment
Cost	10,507	9,387
Accumulated Depreciation	275	133
Net Book Value	10,232	9,254
Oil Pipelines \| Under construction
Plant, property and equipment
Cost	3,678	2,433
Net Book Value	3,678	2,433
Oil Pipelines \| Keystone \| Pipeline
Plant, property and equipment
Cost	4,897	4,904
Accumulated Depreciation	177	80
Net Book Value	4,720	4,824
Oil Pipelines \| Keystone \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	6,829	6,954
Accumulated Depreciation	275	133
Net Book Value	6,554	6,821
Oil Pipelines \| Keystone \| Under construction
Plant, property and equipment
Amount of construction in progress, which remains subject to regulatory approvals	2,000	1,500
Oil Pipelines \| Keystone \| Pumping equipment
Plant, property and equipment
Cost	1,560	1,502
Accumulated Depreciation	75	38
Net Book Value	1,485	1,464
Oil Pipelines \| Keystone \| Tanks and other
Plant, property and equipment
Cost	372	548
Accumulated Depreciation	23	15
Net Book Value	349	533
Oil Pipelines \| Gulf Coast Project \| Under construction
Plant, property and equipment
Amount under construction	1,500	900
Energy
Plant, property and equipment
Cost	7,262	7,157
Accumulated Depreciation	1,429	1,224
Net Book Value	5,833	5,933
Energy \| CrossAlta Gas Storage & Services Ltd.
Plant, property and equipment
Acquisition of ownership interest				40.00%
Energy \| Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	7,126	6,849
Accumulated Depreciation	1,429	1,224
Net Book Value	5,697	5,625
Energy \| Under construction
Plant, property and equipment
Cost	136	308
Net Book Value	136	308
Energy \| Natural Gas - Ravenswood
Plant, property and equipment
Cost	1,799	1,799
Accumulated Depreciation	290	220
Net Book Value	1,509	1,579
Energy \| Natural Gas - Other
Plant, property and equipment
Cost	2,975	3,002
Accumulated Depreciation	746	665
Net Book Value	2,229	2,337
Energy \| Hydro
Plant, property and equipment
Cost	634	620
Accumulated Depreciation	106	90
Net Book Value	528	530
Energy \| Wind
Plant, property and equipment
Cost	907	843
Accumulated Depreciation	118	88
Net Book Value	789	755
Energy \| Natural Gas Storage
Plant, property and equipment
Cost	677	454
Accumulated Depreciation	83	78
Net Book Value	594	376
Energy \| Other
Plant, property and equipment
Cost	134	131
Accumulated Depreciation	86	83
Net Book Value	48	48
Energy \| Facilities under PPAs
Plant, property and equipment
Cost	601	605
Accumulated Depreciation	55	34
Revenues recognized through the sale of electricity	73	53	$ 15
Corporate
Plant, property and equipment
Cost	154	129
Accumulated Depreciation	54	51
Net Book Value	$ 100	$ 78

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
GOODWILL (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Goodwill
Balance at the beginning of the period	$ 3,534	$ 3,457
Foreign exchange rate changes	(76)	77
Balance at the end of the period	3,458	3,534
Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	2,693	2,634
Foreign exchange rate changes	(58)	59
Balance at the end of the period	2,635	2,693
Energy
Goodwill
Balance at the beginning of the period	841	823
Foreign exchange rate changes	(18)	18
Balance at the end of the period	$ 823	$ 841

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
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-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

RATE-REGULATED BUSINESSES (Details)	1 Months Ended			12 Months Ended		60 Months Ended
RATE-REGULATED BUSINESSES (Details)	Jan. 31, 2012	Sep. 30, 2010	Jun. 30, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011
Canadian Mainline \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)				8.08%
Deemed common equity (as a percent)				40.00%	40.00%
After-tax weighted average cost of capital (ATWACC) fair return included in comprehensive application filed with NEB (as a percent)					7.00%
ROE under application, which is equivalent to after-tax weighted average cost of capital (ATWACC) fair return (as a percent)					12.00%
Settlement period under which pipeline were operated and OM&A costs were established						5 years
Alberta System \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)		9.70%
Deemed common equity (as a percent)		40.00%
Foothills \| Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity (as a percent)			9.70%
Deemed common equity (as a percent)			40.00%
GTN \| U.S. Regulated Operations
Rate-regulated business
Period of moratorium during which it is prohibited to take certain actions under NGA	4 years
ANR \| U.S. Regulated Operations \| TC Offshore LLC
Rate-regulated business
Period of operation after which cost and revenue study is required to be filed				3 years

RATE-REGULATED BUSINESSES (Details 2) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets
Total regulatory assets	$ 1,807	$ 1,862
Less: Current portion included in Other Current Assets	178	178
Regulatory assets, noncurrent	1,629	1,684
Regulatory Liabilities
Total regulatory liabilities	368	436
Less: Current portion included in Accounts Payable	100	139
Regulated liabilities, noncurrent	268	297
Foreign exchange on long-term debt
Regulatory Liabilities
Total regulatory liabilities	$ 150	184
Foreign exchange on long-term debt \| Minimum
Regulatory Liabilities
Remaining Recovery/Settlement Period	P1Y
Foreign exchange on long-term debt \| Maximum
Regulatory Liabilities
Remaining Recovery/Settlement Period	P17Y
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Total regulatory liabilities	$ 84	135
Remaining Recovery/Settlement Period	P1Y
Other
Regulatory Liabilities
Total regulatory liabilities	$ 134	117
Deferred income taxes
Regulatory Assets
Total regulatory assets	1,122	1,178
Operating and debt-service regulatory assets
Regulatory Assets
Total regulatory assets	$ 171	172
Remaining Recovery/ Settlement Period	P1Y
Operating and debt-service regulatory assets \| Operating and debt-service regulatory liabilities
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ (50)	102
Adjustment account
Regulatory Assets
Total regulatory assets	$ 80	82
Remaining Recovery/ Settlement Period	P30Y
Adjustment account \| Canadian Mainline
Regulatory Assets
Total regulatory assets			$ 85
Other
Regulatory Assets
Total regulatory assets	$ 434	430
Other \| Other
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	$ 97	$ (106)

EQUITY INVESTMENTS (Details) - CAD ($) $ in Millions		12 Months Ended
EQUITY INVESTMENTS (Details) - CAD ($) $ in Millions	Dec. 18, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	May 03, 2011
Equity Investments
Income/(Loss) from Equity investments		$ 257	$ 415	$ 453
Equity Investments		5,366	5,077
Distributions received from equity investments		436	494	486
Returns of capital		60	101	40
Undistributed earnings		883	1,062	1,141
Income
Revenues		3,860	4,042	3,920
Operating and other expenses		(3,090)	(2,989)	(2,773)
Net income		717	929	1,009
Net income attributable to TransCanada		257	415	$ 453
Balance Sheet
Current assets		1,593	1,430
Non current assets		12,154	11,550
Current liabilities		(1,187)	(1,172)
Non current liabilities		$ (3,787)	$ (3,232)
TC PipeLines, LP
Equity Investments
TransCanada ownership (as a percent)		33.30%	33.30%	38.20%	38.20%
Northern Border
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets		$ 119	$ 120
Bruce Power
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets		$ 918	820
ASTC Power Partnership
Equity Investments
Ownership interest (as a percent)		50.00%
CrossAlta Gas Storage & Services Ltd.
Equity Investments
Assets included in Property, Plant and Equipment, which are owned directly by the company through an undivided interest in the Crossfield joint venture			63
Natural Gas Pipelines
Equity Investments
Income/(Loss) from Equity investments		$ 157	159	$ 153
Income
Net income attributable to TransCanada		$ 157	$ 159	$ 153
Natural Gas Pipelines \| TC PipeLines, LP
Equity Investments
TransCanada ownership (as a percent)		33.30%
Natural Gas Pipelines \| Northern Border
Equity Investments
Ownership interest (as a percent)		16.70%	16.70%	19.10%
Income/(Loss) from Equity investments		$ 72	$ 75	$ 69
Equity Investments		511	545
Income
Net income attributable to TransCanada		$ 72	75	69
Natural Gas Pipelines \| Northern Border \| TC PipeLines, LP
Equity Investments
Ownership interest (as a percent)		50.00%
Natural Gas Pipelines \| Iroquois
Equity Investments
Ownership interest (as a percent)		44.50%
Income/(Loss) from Equity investments		$ 41	40	40
Equity Investments		174	181
Income
Net income attributable to TransCanada		$ 41	40	40
Natural Gas Pipelines \| TQM
Equity Investments
Ownership interest (as a percent)		50.00%
Income/(Loss) from Equity investments		$ 16	17	16
Equity Investments		80	82
Income
Net income attributable to TransCanada		16	17	16
Natural Gas Pipelines \| Other
Equity Investments
Income/(Loss) from Equity investments		28	27	28
Equity Investments		60	72
Income
Net income attributable to TransCanada		28	27	28
Energy
Equity Investments
Income/(Loss) from Equity investments		100	256	300
Income
Net income attributable to TransCanada		100	256	300
Energy \| Other
Equity Investments
Income/(Loss) from Equity investments		8	6	8
Equity Investments		56	132
Income
Net income attributable to TransCanada		$ 8	6	8
Energy \| Bruce A
Equity Investments
Ownership interest (as a percent)		48.90%
Income/(Loss) from Equity investments		$ (149)	33	35
Equity Investments		4,033	3,561
Income
Net income attributable to TransCanada		$ (149)	33	35
Energy \| Bruce B
Equity Investments
Ownership interest (as a percent)		31.60%
Income/(Loss) from Equity investments		$ 163	77	138
Equity Investments		69	115
Income
Net income attributable to TransCanada		$ 163	77	138
Energy \| ASTC Power Partnership
Equity Investments
Ownership interest (as a percent)		50.00%
Income/(Loss) from Equity investments		$ 40	84	41
Equity Investments		42	58
Income
Net income attributable to TransCanada		$ 40	84	41
Energy \| Portlands Energy
Equity Investments
Ownership interest (as a percent)		50.00%
Income/(Loss) from Equity investments		$ 28	33	33
Equity Investments		341	313
Income
Net income attributable to TransCanada		28	33	33
Energy \| CrossAlta Gas Storage & Services Ltd.
Equity Investments
Income/(Loss) from Equity investments		10	23	45
Equity Investments			18
Income
Net income attributable to TransCanada		$ 10	$ 23	$ 45
Energy \| CrossAlta Gas Storage & Services Ltd.
Equity Investments
Percentage of interest acquired	40.00%
Ownership interest after acquisition (as a percent)	100.00%
Balance Sheet
Ownership interest prior to acquisition (as a percent)	60.00%

INTANGIBLE AND OTHER ASSETS (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
INTANGIBLES AND OTHER ASSETS
PPAs			$ 376	$ 428
Loans and advances			196	224
Fair value of derivative contracts			187	202
Deferred income tax assets			105	132
Employee post-retirement benefits			11
Other			468	480
Intangibles and Other Assets			1,343	1,466
Amount related to PPAs which are included in intangibles and other assets
Cost			810	810
Accumulated Amortization			434	382
Net Book Value			376	428
Amortization expense			52	52	$ 52
Expected annual amortization expense
2013			52
2014			52
2015			52
2016			52
2017			52
Note receivable
Note receivable from the seller of Ravenswood			$ 236	265
Interest rate on note receivable from the seller of Ravenswood (as a percent)			6.75%
Current portion of the note receivable			$ 40	41
Pre-tax charge recorded			$ 1,938	2,285	1,780
Advances to APG
Share of project pre-development costs agreed to be financed (as a percent)			33.30%
Valuation provision recorded on the loan to the APG					$ 146
Sheerness
INTANGIBLES AND OTHER ASSETS
PPAs			$ 312	351
Amount related to PPAs which are included in intangibles and other assets
Cost			585	585
Accumulated Amortization			273	234
Net Book Value			312	351
Sundance A
INTANGIBLES AND OTHER ASSETS
PPAs			64	77
Amount related to PPAs which are included in intangibles and other assets
Cost			225	225
Accumulated Amortization			161	148
Net Book Value			$ 64	77
Note receivable
Pre-tax charge recorded	$ (50)	$ 30		$ 20

NOTES PAYABLE (Details) $ in Millions, $ in Millions	12 Months Ended
NOTES PAYABLE (Details) $ in Millions, $ in Millions	Dec. 31, 2012 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2011 CAD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2010 CAD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 CAD ($)
Notes payable
Amount outstanding							$ 2,275	$ 1,863
Notes payable \| Canadian dollars
Notes payable
Amount outstanding							$ 803	$ 466
Weighted Average Interest Rate per Annum (as a percent)	1.20%		1.20%				1.20%	1.20%
Notes payable \| U.S. dollars
Notes payable
Amount outstanding	$ 1,480		$ 1,373				$ 1,472	$ 1,397
Weighted Average Interest Rate per Annum (as a percent)	0.40%		0.50%				0.40%	0.50%
Revolving and demand credit facilities
Notes payable
Amount available for borrowing							$ 5,300
Committed, syndicated, revolving, extendible credit facility \| TransCanada PipeLines Limited
Notes payable
Maximum borrowing capacity							2,000
Cost to maintain the facility		$ 4		$ 2		$ 2
Committed, syndicated, revolving, extendible credit facility \| TC Keystone
Notes payable
Maximum borrowing capacity	$ 1,000
Cost to maintain the facility		$ 1		4		5
Committed, syndicated, revolving, extendible credit facility \| U.S. dollars \| TCPL USA
Notes payable
Maximum borrowing capacity	1,000
Cost to maintain the facility	1		$ 4		$ 4
Senior revolving credit facility \| TCPL USA
Notes payable
Maximum borrowing capacity	300
Cost to maintain the facility				$ 1		$ 1
Initial maximum borrowing capacity	$ 1,000
Demand credit facility
Notes payable
Maximum borrowing capacity							1,000
Amount used for letters of credit							$ 627

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
ACCOUNTS PAYABLE AND OTHER
Trade payables	$ 923	$ 696
Fair value of derivative contracts	283	485
Dividends payable	320	305
Regulatory liabilities	100	139
Deferred income tax liabilities		81
Other	718	653
Total	$ 2,344	$ 2,359

Fair values as of the balance sheet date of all liabilities resulting from contracts that meet the criteria of being accounted for as derivative instruments, and which are expected to be extinguished or otherwise disposed of within a year or the normal operating cycle, if longer, net of the effects of master netting arrangements.

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Carrying value as of the balance sheet date of obligations incurred through that date and payable arising from transactions not otherwise specified in the taxonomy. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
OTHER LONG-TERM LIABILITIES
Employee post-retirement benefits	$ 482	$ 321
Fair value of derivative contracts	186	349
Guarantees	17	118
Asset retirement obligations	72	65
Other	125	76
Deferred amounts	$ 882	$ 929

Fair values as of the balance sheet date of all liabilities resulting from contracts that meet the criteria of being accounted for as derivative instruments, and which are expected to be extinguished or otherwise disposed of after one year or beyond the normal operating cycle, if longer, net of the effects of master netting arrangements.

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This represents the noncurrent liability for underfunded plans recognized in the balance sheet that is associated with the defined benefit pension plans and other postretirement defined benefit plans.

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LONG-TERM DEBT (Details) $ in Millions, $ in Millions			1 Months Ended													12 Months Ended
LONG-TERM DEBT (Details) $ in Millions, $ in Millions	Jan. 31, 2012 USD ($)	Aug. 31, 2011 USD ($)	Aug. 31, 2012 USD ($)	May 31, 2012 USD ($)	Mar. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Nov. 30, 2011 CAD ($)	Jun. 30, 2011 USD ($)	May 31, 2011 USD ($)	May 31, 2011 CAD ($)	Jan. 31, 2011 CAD ($)	Sep. 30, 2010 USD ($)	Aug. 31, 2010 CAD ($)	Jun. 30, 2010 USD ($)	Feb. 28, 2010 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2011 CAD ($)	Dec. 31, 2010 CAD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 CAD ($)	Jul. 31, 2011 USD ($)
Long-term debt
Long-term debt																					$ 18,913	$ 18,659
Less: Current Portion of Long-Term Debt																					894	935
Non-current portion of long-term debt																					18,019	17,724
Principal repayments on long-term debt for the next five years
2013																					894
2014																					970
2015																					1,561
2016																					1,214
2017																					555
Interest Expense
Capitalized interest																	$ (300)		$ (302)	$ (587)
Amortization and other financial charges																	7		6	59
Total																	976		937	701
Interest payments
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects																	966		926	652
Interest rate swap agreements
Long-term debt
Fair value adjustments																	(10)		(13)
Amount of debt in fair value hedge						$ 350										$ 350		$ 350
Short-term debt
Interest Expense
Interest expense																	16		16	15
Total long-term debt (excluding junior subordinated notes)
Interest Expense
Interest expense																	1,190		1,154	1,149
Junior subordinated notes
Interest Expense
Interest expense																	$ 63		$ 63	$ 65
TRANSCANADA PIPELINES LIMITED \| Total long-term debt (excluding junior subordinated notes)
Long-term debt
Long-term debt																					15,878	14,792
TRANSCANADA PIPELINES LIMITED \| Debentures \| Canadian dollars
Long-term debt
Long-term debt																					$ 874	$ 874
Effective interest rates (as a percent)						10.90%										10.90%		10.90%			10.90%	10.90%
TRANSCANADA PIPELINES LIMITED \| Debentures \| U.S. dollars
Long-term debt
Long-term debt						$ 600										$ 400		$ 600			$ 398	$ 610
Effective interest rates (as a percent)						9.50%										9.90%		9.50%			9.90%	9.50%
TRANSCANADA PIPELINES LIMITED \| 10.50 % debentures
Long-term debt
Interest rate (as a percent)													10.50%
Debt repaid/retired													$ 130
TRANSCANADA PIPELINES LIMITED \| Medium-Term Notes \| Canadian dollars
Long-term debt
Long-term debt																					$ 4,549	$ 4,549
Effective interest rates (as a percent)						5.90%										5.90%		5.90%			5.90%	5.90%
TRANSCANADA PIPELINES LIMITED \| 3.65 % medium-term notes, due November 15, 2021
Long-term debt
Debt issued							$ 500
Interest rate (as a percent)							3.65%
TRANSCANADA PIPELINES LIMITED \| 4.55 % medium-term notes, due November 15, 2041
Long-term debt
Debt issued							$ 250
Interest rate (as a percent)							4.55%
TRANSCANADA PIPELINES LIMITED \| 9.5 % medium term notes
Long-term debt
Interest rate (as a percent)									9.50%	9.50%
Debt repaid/retired										$ 60
TRANSCANADA PIPELINES LIMITED \| 4.3 % medium term notes
Long-term debt
Interest rate (as a percent)											4.30%
Debt repaid/retired											$ 300
TRANSCANADA PIPELINES LIMITED \| 6.125 % medium term notes \| U.S. dollars
Long-term debt
Interest rate (as a percent)															6.125%
Debt repaid/retired															$ 120
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes \| Interest rate swap agreements
Long-term debt
Fair value adjustments																$ 10		$ 13
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 8,626										$ 10,126		$ 8,626			$ 10,057	$ 8,759
Effective interest rates (as a percent)						6.20%										5.60%		6.20%			5.60%	6.20%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes \| U.S. dollars \| Interest rate swap agreements
Long-term debt
Amount of debt in fair value hedge						$ 350										$ 350		$ 350
TRANSCANADA PIPELINES LIMITED \| 2.5 % senior unsecured notes, due August 1, 2022 \| U.S. dollars
Long-term debt
Debt issued			$ 1,000
Interest rate (as a percent)			2.50%
TRANSCANADA PIPELINES LIMITED \| 8.625 % senior unsecured notes \| U.S. dollars
Long-term debt
Interest rate (as a percent)				8.625%
Debt repaid/retired				$ 200
TRANSCANADA PIPELINES LIMITED \| 0.875 % senior unsecured notes, due March 2, 2015 \| U.S. dollars
Long-term debt
Debt issued					$ 500
Interest rate (as a percent)					0.875%
TRANSCANADA PIPELINES LIMITED \| 3.80 % senior unsecured notes, due October 1, 2020 \| U.S. dollars
Long-term debt
Debt issued												$ 1,000
Interest rate (as a percent)												3.80%
TRANSCANADA PIPELINES LIMITED \| 3.4 % senior unsecured notes, due June 1, 2015 \| U.S. dollars
Long-term debt
Debt issued														$ 500
Interest rate (as a percent)														3.40%
TRANSCANADA PIPELINES LIMITED \| 6.1 % senior unsecured notes, due June 1, 2040 \| U.S. dollars
Long-term debt
Debt issued														$ 750
Interest rate (as a percent)														6.10%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes \| U.S. dollars
Long-term debt
Effective interest rates (as a percent)						6.50%										6.50%		6.50%			6.50%	6.50%
Long-term debt
Interest rate (as a percent)																6.35%					6.35%
NOVA GAS TRANSMISSION LTD \| Total long-term debt (excluding junior subordinated notes)
Long-term debt
Long-term debt																					$ 1,117	$ 1,305
NOVA GAS TRANSMISSION LTD \| 8.5 % debentures \| U.S. dollars
Long-term debt
Interest rate (as a percent)																8.50%					8.50%
Debt repaid/retired																$ 175
NOVA GAS TRANSMISSION LTD \| Debentures with retraction provisions
Long-term debt
Face amount																					$ 225
NOVA GAS TRANSMISSION LTD \| Debentures with retraction provisions \| Maximum
Long-term debt
Percentage of principal plus accrued and unpaid interest redeemable at specified repayment dates																8.00%	8.00%
NOVA GAS TRANSMISSION LTD \| Medium-Term Notes \| Canadian dollars
Long-term debt
Long-term debt																					$ 504	$ 504
Effective interest rates (as a percent)						7.40%										7.40%		7.40%			7.40%	7.40%
NOVA GAS TRANSMISSION LTD \| Medium-Term Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 33										$ 33		$ 33			$ 32	$ 33
Effective interest rates (as a percent)						7.50%										7.50%		7.50%			7.50%	7.50%
NOVA GAS TRANSMISSION LTD \| Debentures and Notes \| Canadian dollars
Long-term debt
Long-term debt																					$ 382	$ 387
Effective interest rates (as a percent)						11.50%										11.50%		11.50%			11.50%	11.50%
NOVA GAS TRANSMISSION LTD \| Debentures and Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 375										$ 200		$ 375			$ 199	$ 381
Effective interest rates (as a percent)						8.20%										7.90%		8.20%			7.90%	8.20%
TRANSCANADA PIPELINE USA LTD \| Bank Loan (credit facility) \| U.S. dollars
Long-term debt
Long-term debt						$ 500												$ 500				$ 509
Effective interest rates (as a percent)						0.60%												0.60%				0.60%
Long-term debt
Initial maximum borrowing capacity																							$ 1,000
Borrowing capacity																$ 300
TRANSCANADA PIPELINE USA LTD \| Term loan \| U.S. dollars
Long-term debt
Debt repaid/retired	$ 500	$ 200
Amount outstanding						$ 500												$ 500
TRANSCANADA PIPELINE USA LTD \| Revolving facility \| U.S. dollars
Long-term debt
Borrowing capacity																300
ANR PIPELINE COMPANY \| Senior Unsecured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 432										$ 432		$ 432			$ 430	$ 438
Effective interest rates (as a percent)						8.90%										8.90%		8.90%			8.90%	8.90%
GAS TRANSMISSION NORTHWEST CORPORATION \| Senior Unsecured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 325										$ 325		$ 325			$ 323	$ 331
Effective interest rates (as a percent)						5.50%										5.50%		5.50%			5.50%	5.50%
TC PIPELINES, LP \| U.S. dollars \| GTN LLC
Long-term debt
Ownership interest (as a percent)									25.00%	25.00%
TC PIPELINES, LP \| U.S. dollars \| Bison LLC
Long-term debt
Ownership interest (as a percent)									25.00%	25.00%
TC PIPELINES, LP \| Total long-term debt (excluding junior subordinated notes)
Long-term debt
Long-term debt																					$ 658	$ 725
TC PIPELINES, LP \| Senior Unsecured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 350										$ 350		$ 350			$ 348	$ 356
Effective interest rates (as a percent)						4.70%										4.70%		4.70%			4.70%	4.70%
TC PIPELINES, LP \| 4.65 % senior unsecured notes, due 2021 \| U.S. dollars
Long-term debt
Debt issued								$ 350
Interest rate (as a percent)								4.65%
TC PIPELINES, LP \| Term loan \| U.S. dollars
Long-term debt
Debt repaid/retired						$ 300
TC PIPELINES, LP \| Revolving facility \| U.S. dollars
Long-term debt
Borrowing capacity																							$ 500
Amount outstanding						363										$ 312		$ 363
Draws from credit facility									$ 125
TC PIPELINES, LP \| Unsecured Loan \| U.S. dollars
Long-term debt
Long-term debt						$ 363										$ 312		$ 363			$ 310	$ 369
Effective interest rates (as a percent)						1.60%										1.50%		1.60%			1.50%	1.60%
TC PIPELINES, LP \| Bridge loan facility \| U.S. dollars
Long-term debt
Draws from credit facility									$ 61
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 373										$ 354		$ 373			$ 352	$ 379
Effective interest rates (as a percent)						7.80%										7.80%		7.80%			7.80%	7.80%
TUSCARORA GAS TRANSMISSION COMPANY \| Senior Secured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 30										$ 27		$ 30			$ 27	$ 31
Effective interest rates (as a percent)						4.40%										4.00%		4.40%			4.00%	4.40%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Secured Notes \| U.S. dollars
Long-term debt
Long-term debt						$ 147										$ 129		$ 147			$ 128	$ 149
Effective interest rates (as a percent)						6.10%										6.10%		6.10%			6.10%	6.10%

INCOME TAXES (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES (Details) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current
Canada	$ 167	$ 212	$ 31
Foreign	14	(2)	(170)
Total	181	210	(139)
Deferred
Canada	69	139	175
Foreign	216	226	351
Total	285	365	526
Total Income Tax Expense/ (Recovery)	466	575	387
Geographic Components of Income
Canada	842	1,176	811
Foreign	1,096	1,109	969
Income before Income Taxes	1,938	2,285	1,780
Reconciliation of Income Tax Expense
Income before Income Taxes	$ 1,938	$ 2,285	$ 1,780
Federal and provincial statutory tax rate (as a percent)	25.00%	26.50%	28.00%
Expected income tax expense	$ 485	$ 605	$ 498
Income tax differential related to regulated operations	41	42	8
Higher / (lower) effective foreign tax rates	1	(5)	(36)
Income from equity investments and non-controlling interests	(40)	(45)	(40)
Other	(21)	(22)	(43)
Total Income Tax Expense/ (Recovery)	466	575	$ 387
Deferred Income Tax Assets
Operating loss carryforwards	1,024	900
Financial instruments	88	166
Pension and other post-employment benefits	83	42
Deferred amounts	49	49
Other	92	132
Total	1,336	1,289
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, equipment and PPAs	3,804	3,609
Equity investments	578	457
Taxes on future revenue requirement	283	295
Unrealized foreign exchange gains on long-term debt	159	133
Other	70	87
Total	4,894	4,581
Net deferred income tax liabilities	3,558	3,292
Deferred Income Tax Assets
Other current assets	290	248
Intangible and other assets	105	132
Total	395	380
Deferred Income Tax Liabilities
Accounts payable and other		81
Deferred income taxes	3,953	3,591
Total	3,953	3,672
Net Deferred Income Tax Liabilities
Net deferred income tax liabilities	$ 3,558	$ 3,292

INCOME TAXES (Details 2) $ in Millions, $ in Millions	12 Months Ended
INCOME TAXES (Details 2) $ in Millions, $ in Millions	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 CAD ($)	Dec. 31, 2010 CAD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2011 CAD ($)
Net operating loss carryforwards
Income tax payments, net of refunds	$ 190	$ (84)	$ 53
Unremitted earnings of foreign investments
Net operating loss carryforwards
Deferred income tax liabilities on the unremitted earnings of foreign investments					$ 144		$ 136
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards					$ 865		$ 450
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards				$ 2,174		$ 2,119

INCOME TAXES (Details 3) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES (Details 3) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of the annual changes in the total unrecognized tax benefit
Unrecognized tax benefits at beginning of year	$ 52	$ 62	$ 55
Gross increases - tax positions in prior years	2	9	7
Gross decreases - tax positions in prior years	(6)	(7)	(1)
Gross increases - tax positions in current year	9	11	9
Settlements			(7)
Lapses of statute of limitations	(8)	(23)	(1)
Unrecognized tax benefits at end of year	49	52	62
Income tax interest and penalties
Interest expense (reversal) reflected within net tax expense	(2)	(12)	$ 3
Accrued interest expense	5	$ 7
Expected enactment of Canadian federal tax legislation
SignificantChangeInUnrecognizedTaxBenefitsIsReasonablyPossibleLineItems
Expected favorable income tax adjustment	$ 25

JUNIOR SUBORDINATED NOTES (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2011 CAD ($)
Junior subordinated notes
Amount outstanding		$ 994		$ 1,016
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes \| U.S. dollars
Junior subordinated notes
Amount outstanding	$ 1,000	$ 994	$ 1,000	$ 1,016
Effective interest rate (as a percent)	6.50%	6.50%	6.50%	6.50%
Interest rate until May 15, 2017 (as a percent)	6.35%	6.35%
Variable rate basis after May 15, 2017	3 months LIBOR
Interest rate margin after May 15, 2017 (as a percent)	2.21%	2.21%
Optional period for which payment of interest can be deferred	10 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest to the date of redemption	100.00%

NON-CONTROLLING INTERESTS (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
	May 03, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest		$ 1,425	$ 1,465
Non-controlling interests included in the Consolidated Statement of Income
Net income attributable to non-controlling interests		118	129	$ 115
TC PipeLines, LP
Cash Dividends
Fees received for services provided		3	2	2
TC PipeLines, LP \| GTN
Additional information
Ownership interest from TransCanada to TC Pipelines	25.00%
TC PipeLines, LP \| Bison
Additional information
Ownership interest from TransCanada to TC Pipelines	25.00%
TransCanada PipeLines Limited \| Series U
Non-controlling interest included in the Consolidated Balance Sheet
Preferred shares of TCPL		$ 195	$ 195
Preferred Shares of TCPL
Number of Shares Outstanding		4,000	4,000
Dividend Rate per Share (in Canadian dollars per share)		$ 2.80	$ 2.80
Redemption Price per Share (in Canadian dollars per share)		$ 50.00
Cash Dividends
Cash dividends paid		$ 22	$ 22	$ 22
Cash dividends paid (in Canadian dollars per share)		$ 2.80	$ 2.80	$ 2.80
TransCanada PipeLines Limited \| Series Y
Non-controlling interest included in the Consolidated Balance Sheet
Preferred shares of TCPL		$ 194	$ 194
Preferred Shares of TCPL
Number of Shares Outstanding		4,000	4,000
Dividend Rate per Share (in Canadian dollars per share)		$ 2.80	$ 2.80
Redemption Price per Share (in Canadian dollars per share)		$ 50.00
Cash Dividends
Cash dividends paid		$ 22	$ 22	$ 22
Cash dividends paid (in Canadian dollars per share)		$ 2.80	$ 2.80	$ 2.80
Portland
Cash Dividends
Fees received for services provided		$ 7	$ 7	$ 7
Noncontrolling Interest [Member] \| TC PipeLines, LP
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest		953	997
Non-controlling interests included in the Consolidated Statement of Income
Net income attributable to non-controlling interests		$ 91	101	87
Additional information
Percentage of non-controlling interests	61.80%	66.70%
Noncontrolling Interest [Member] \| TransCanada PipeLines Limited
Non-controlling interest included in the Consolidated Balance Sheet
Preferred shares of TCPL		$ 389	389
Non-controlling interests included in the Consolidated Statement of Income
Preferred share dividends of TCPL		22	22	22
Noncontrolling Interest [Member] \| Portland
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest		83	79
Non-controlling interests included in the Consolidated Statement of Income
Net income attributable to non-controlling interests		$ 5	$ 6	$ 6
Additional information
Percentage of non-controlling interests		38.30%	38.30%	38.30%

COMMON SHARES (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	704,000
Outstanding at the beginning of the period	$ 12,011
Dividend reinvestment and share purchase plan (in shares)		5,400	10,700
Dividend reinvestment and share purchase plan		$ 202	$ 378
Exercise of options (in shares)	1,600	2,260	1,201
Outstanding at the end of the period (in shares)	705,000	704,000
Outstanding at the end of the period	$ 12,069	$ 12,011
Net Income per Share
Weighted average number of common shares outstanding used to calculate basic earnings per share	705,000	702,000	691,000
Weighted average number of common shares outstanding used to calculate diluted earnings per share	706,000	703,000	692,000
Common Shares
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	703,861	696,230	684,359
Outstanding at the beginning of the period	$ 12,011	$ 11,745	$ 11,338
Dividend reinvestment and share purchase plan (in shares)		5,371	10,670
Dividend reinvestment and share purchase plan		$ 202	$ 378
Exercise of options (in shares)	1,600	2,260	1,201
Exercise of options	$ 58	$ 64	$ 29
Outstanding at the end of the period (in shares)	705,461	703,861	696,230
Outstanding at the end of the period	$ 12,069	$ 12,011	$ 11,745
Net Income per Share
Weighted average number of common shares outstanding used to calculate basic earnings per share	704,600	701,600	690,500
Weighted average number of common shares outstanding used to calculate diluted earnings per share	705,700	702,800	691,700

COMMON SHARES (Details 2) - $ / shares shares in Thousands	12 Months Ended
COMMON SHARES (Details 2) - $ / shares shares in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Number of Options
Outstanding at the beginning of the period (in shares)	7,100	8,406	8,274
Granted (in shares)	1,978	970	1,367
Exercised (in shares)	(1,600)	(2,260)	(1,201)
Forfeited (in shares)	(44)	(16)	(34)
Outstanding at the end of the period (in shares)	7,434	7,100	8,406
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share)	$ 35.44	$ 32.57	$ 30.56
Granted (in Canadian dollars per share)	42.03	38.02	35.32
Exercised (in Canadian dollars per share)	33.13	25.86	22.04
Forfeited (in Canadian dollars per share)	36.55	35.83	27.35
Outstanding at the end of the period (in Canadian dollars per share)	$ 37.69	$ 35.44	$ 32.57
Options Exercisable
Options Exercisable (in shares)	4,588	5,165	6,458	6,212

COMMON SHARES (Details 3) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Options Outstanding
Number of Options (in shares)	7,434
Weighted Average Exercise Price (in Canadian dollars per share)	$ 37.69
Weighted Average Remaining Contractual Life	3 years 10 months 24 days
Options Exercisable
Number of Options (in shares)	4,588
Weighted Average Exercise Price (in Canadian dollars per share)	$ 35.93
Weighted Average Remaining Contractual Life	2 years 8 months 12 days
Additional disclosure
Common shares reserved for future issuance under stock option plan	2,400
Weighted average fair value of options granted (in Canadian dollars per share)	$ 5.08	$ 2.94	$ 5.76
Contractual life of options granted	7 years
Award vesting right percentage	33.30%
Award vesting period	3 years
Weighted average assumptions used in binomial model for determining the fair value of awards granted
Expected life	5 years 10 months 24 days	4 years	4 years
Interest rate (as a percent)	1.60%	2.10%	2.00%
Volatility (as a percent)	19.00%	14.00%	27.00%
Dividend yield (as a percent)	4.20%	4.30%	4.70%
Forfeiture rate (as a percent)	15.00%	15.00%	15.00%
Amount expensed for stock awards, with a corresponding increase in additional paid-in capital	$ 5	$ 5	$ 4
Total intrinsic value of options exercised	18	$ 34	$ 17
Aggregate intrinsic value of total options exercisable	51
Total intrinsic value of options outstanding	$ 69
Number of shares vested	1,000	900	1,500
Fair value of shares vested	$ 49	$ 42	$ 57
Range of exercise price per share $30.10 to $31.97
Stock options outstanding and exercisable by exercise price range
Exercise price, low end of range (in Canadian dollars per share)	$ 30.10
Exercise price, high end of range (in Canadian dollars per share)	$ 31.97
Options Outstanding
Number of Options (in shares)	1,093
Weighted Average Exercise Price (in Canadian dollars per share)	$ 31.95
Weighted Average Remaining Contractual Life	3 years 2 months 12 days
Options Exercisable
Number of Options (in shares)	1,093
Weighted Average Exercise Price (in Canadian dollars per share)	$ 31.95
Weighted Average Remaining Contractual Life	3 years 2 months 12 days
Range of exercise price per share $32.40 to $35.08
Stock options outstanding and exercisable by exercise price range
Exercise price, low end of range (in Canadian dollars per share)	$ 32.40
Exercise price, high end of range (in Canadian dollars per share)	$ 35.08
Options Outstanding
Number of Options (in shares)	1,387
Weighted Average Exercise Price (in Canadian dollars per share)	$ 34.64
Weighted Average Remaining Contractual Life	4 years
Options Exercisable
Number of Options (in shares)	1,160
Weighted Average Exercise Price (in Canadian dollars per share)	$ 34.55
Weighted Average Remaining Contractual Life	4 years
Range of exercise price per share $35.23 to $37.93
Stock options outstanding and exercisable by exercise price range
Exercise price, low end of range (in Canadian dollars per share)	$ 35.23
Exercise price, high end of range (in Canadian dollars per share)	$ 37.93
Options Outstanding
Number of Options (in shares)	1,202
Weighted Average Exercise Price (in Canadian dollars per share)	$ 37.52
Weighted Average Remaining Contractual Life	5 years
Options Exercisable
Number of Options (in shares)	556
Weighted Average Exercise Price (in Canadian dollars per share)	$ 37.22
Weighted Average Remaining Contractual Life	4 years 10 months 24 days
Range of exercise price per share $38.10 to $39.75
Stock options outstanding and exercisable by exercise price range
Exercise price, low end of range (in Canadian dollars per share)	$ 38.10
Exercise price, high end of range (in Canadian dollars per share)	$ 39.75
Options Outstanding
Number of Options (in shares)	1,750
Weighted Average Exercise Price (in Canadian dollars per share)	$ 38.83
Weighted Average Remaining Contractual Life	1 year 8 months 12 days
Options Exercisable
Number of Options (in shares)	1,750
Weighted Average Exercise Price (in Canadian dollars per share)	$ 38.83
Weighted Average Remaining Contractual Life	1 year 8 months 12 days
Range of exercise price per share $41.65 to $45.29
Stock options outstanding and exercisable by exercise price range
Exercise price, low end of range (in Canadian dollars per share)	$ 41.65
Exercise price, high end of range (in Canadian dollars per share)	$ 45.29
Options Outstanding
Number of Options (in shares)	2,002
Weighted Average Exercise Price (in Canadian dollars per share)	$ 42.03
Weighted Average Remaining Contractual Life	6 years 1 month 6 days
Options Exercisable
Number of Options (in shares)	29
Weighted Average Exercise Price (in Canadian dollars per share)	$ 41.87
Weighted Average Remaining Contractual Life	5 years 10 months 24 days

COMMON SHARES (Details 4) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Apr. 28, 2011	Feb. 28, 2011	Dec. 31, 2012 CAD ($) item $ / shares shares	Dec. 31, 2011 CAD ($) $ / shares shares	Dec. 31, 2010 CAD ($) $ / shares shares
Shareholder Rights Plan
Number of rights entitled to each common share \| item			1
Number of common shares entitled to be purchased under each right \| shares			2
Cash Dividends
Cash dividends paid \| $			$ 1,226	$ 961	$ 710
Cash dividends paid (in Canadian dollars per share) \| $ / shares			$ 1.74	$ 1.66	$ 1.58
Dividend Reinvestment Plan
Period before dividend payment during which common shares from Treasury were issued at a discount in lieu of cash dividends	5 days
Discount on issuance of common shares from the average market price (as a percent)		2.00%			3.00%
Common stock issued in accordance with the DRP (in shares) \| shares				5,400,000	10,700,000
Value of common shares issued in accordance with the DRP in lieu of making cash dividend payments \| $				$ 202	$ 378

PREFERRED SHARES (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	1 Months Ended		12 Months Ended
	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Preferred Shares
Preferred shares			$ 1,224	$ 1,224
Series 1
Preferred Shares
Preferred shares, authorized			22,000	22,000
Preferred shares, outstanding			22,000	22,000
Dividend Rate per Share (in Canadian dollars per share)			$ 1.15	$ 1.15
Redemption Price per Share (in Canadian dollars per share)			$ 25.00	$ 25.00
Preferred shares			$ 539	$ 539
Dividend rate reset period			5 years
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			5 years
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.92%
Period of subsequent interval for redemption of preferred stock			5 years
Period of subsequent interval for conversion of preferred stock			5 years
Cash Dividends
Cash dividends paid			$ 25	$ 25	$ 24
Cash dividends paid (in Canadian dollars per share)			$ 1.15	$ 1.15	$ 1.15
Series 2
Preferred Shares
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			90 days
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.92%
Series 3
Preferred Shares
Preferred shares, authorized			14,000	14,000
Preferred shares, outstanding			14,000	14,000
Dividend Rate per Share (in Canadian dollars per share)			$ 1.00	$ 1.00
Redemption Price per Share (in Canadian dollars per share)			$ 25.00	$ 25.00
Preferred shares			$ 343	$ 343
Initial period of fixed cumulative quarterly dividend payment		5 years
Dividend rate reset period			5 years
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			5 years
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.28%
Period of subsequent interval for redemption of preferred stock			5 years
Period of subsequent interval for conversion of preferred stock			5 years
Cash Dividends
Cash dividends paid			$ 14	$ 14	$ 11
Cash dividends paid (in Canadian dollars per share)			$ 1.00	$ 1.00	$ 0.8041
Series 4
Preferred Shares
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			90 days
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.28%
Series 5
Preferred Shares
Preferred shares, authorized			14,000	14,000
Preferred shares, outstanding			14,000	14,000
Dividend Rate per Share (in Canadian dollars per share)			$ 1.10	$ 1.10
Redemption Price per Share (in Canadian dollars per share)			$ 25.00	$ 25.00
Preferred shares			$ 342	$ 342
Initial period of fixed cumulative quarterly dividend payment	5 years 6 months
Dividend rate reset period			5 years
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			5 years
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.54%
Period of subsequent interval for redemption of preferred stock			5 years
Period of subsequent interval for conversion of preferred stock			5 years
Cash Dividends
Cash dividends paid			$ 16	$ 16	$ 9
Cash dividends paid (in Canadian dollars per share)			$ 1.10	$ 1.10	$ 0.3707
Series 6
Preferred Shares
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum			90 days
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum			1.54%

EMPLOYEE POST-RETIREMENT BENEFITS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	12 years	12 years
Amount expensed for the Savings Plan and DC Plans	$ 24	$ 23	$ 21
Total cash payments for employee post-retirement benefits, consisting of cash contributed by the company to the DB Plans and other benefit plans	114	93	$ 127
Change in Plan Assets
Plan assets at fair value - beginning of year	1,685
Plan assets at fair value - end of year	1,857	1,685
Amounts recognized in the Balance Sheet
Intangible and Other Assets	11
Other Long-Term Liabilities	$ (482)	$ (321)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Expected average remaining service life of employees over which past service costs are amortized	9 years	8 years	8 years
Change in Benefit Obligation
Benefit obligation - beginning of year	$ 1,836	$ 1,622
Service cost	66	54	$ 50
Interest cost	94	91	89
Employee contributions	4	4
Benefits paid	(79)	(71)
Actuarial loss	227	131
Foreign exchange rate changes	(6)	5
Benefit obligation - end of year	2,142	1,836	1,622
Change in Plan Assets
Plan assets at fair value - beginning of year	1,656	1,636
Actual return on plan assets	165	21
Employer contributions	83	62
Employee contributions	4	4
Benefits paid	(79)	(71)
Foreign exchange rate changes	(4)	4
Plan assets at fair value - end of year	1,825	1,656	1,636
Funded Status - Plan (Deficit)	(317)	(180)
Amounts recognized in the Balance Sheet
Other Long-Term Liabilities	(317)	(180)
Total	(317)	(180)
Pension Benefit Plans \| Canadian
Employee post-retirement benefits
Letter of credit to the DB Plan	48	27
Total amount outstanding under letters of credit	75
Other Post-Retirement Benefit Plans
Change in Benefit Obligation
Benefit obligation - beginning of year	170	159
Service cost	2	2	2
Interest cost	8	9	9
Employee contributions	1	1
Benefits paid	(9)	(9)
Actuarial loss	16	7
Foreign exchange rate changes	(2)	1
Benefit obligation - end of year	186	170	159
Change in Plan Assets
Plan assets at fair value - beginning of year	29	29
Actual return on plan assets	4
Employer contributions	7	8
Employee contributions	1	1
Benefits paid	(9)	(9)
Plan assets at fair value - end of year	32	29	$ 29
Funded Status - Plan (Deficit)	(154)	(141)
Amounts recognized in the Balance Sheet
Intangible and Other Assets	11
Other Long-Term Liabilities	(165)	(141)
Total	$ (154)	$ (141)

EMPLOYEE POST-RETIREMENT BENEFITS (Details 2) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Funded status based on accumulated benefit obligation
Plan assets at fair value	$ 1,857	$ 1,685
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Benefit obligation	(2,142)	(1,836)
Plan assets at fair value	1,825	1,656
Funded Status - Deficit	(317)	(180)
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded
Accumulated benefit obligation	(1,966)	(446)
Plan assets at fair value	1,825	391
Funded Status - Deficit	$ (141)	$ (55)
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	$ (1,966)	$ (1,691)
Plan assets at fair value	1,825	1,656	$ 1,636
Funded Status - Deficit	$ (141)	$ (35)
Pension Benefit Plans \| Debt securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	36.00%	39.00%
Amount of the Company's debt or the Company's common shares included in plan assets	$ 2	$ 2
Percentage of the Company's debt or the Company's common shares included in plan assets as compared to total plan assets	0.10%	0.10%
Pension Benefit Plans \| Debt securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	35.00%
Pension Benefit Plans \| Debt securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	60.00%
Pension Benefit Plans \| Equity Securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	64.00%	61.00%
Amount of the Company's debt or the Company's common shares included in plan assets	$ 3	$ 3
Percentage of the Company's debt or the Company's common shares included in plan assets as compared to total plan assets	0.20%	0.20%
Pension Benefit Plans \| Equity Securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	40.00%
Pension Benefit Plans \| Equity Securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations (as a percent)	65.00%
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Benefit obligation	$ (186)	$ (170)
Plan assets at fair value	32	29
Funded Status - Deficit	(154)	(141)
Funded status based on accumulated benefit obligation
Plan assets at fair value	$ 32	$ 29	$ 29

EMPLOYEE POST-RETIREMENT BENEFITS (Details 3) - CAD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee post-retirement benefits
Fair value of plan assets	$ 1,857	$ 1,685
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 757	$ 675
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,081	990
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	19	20
Cash and cash equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 17	$ 25
Percentage of Total Portfolio	1.00%	1.00%
Cash and cash equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 17	$ 25
Equity Securities \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 513	$ 469
Percentage of Total Portfolio	28.00%	28.00%
Equity Securities \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 347	$ 306
Percentage of Total Portfolio	19.00%	18.00%
Equity Securities \| International
Employee post-retirement benefits
Fair value of plan assets	$ 294	$ 256
Percentage of Total Portfolio	16.00%	15.00%
Equity Securities \| Global
Employee post-retirement benefits
Fair value of plan assets	$ 13
Equity Securities \| Quoted Prices in Active Markets (Level I) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	400	$ 374
Equity Securities \| Quoted Prices in Active Markets (Level I) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	309	251
Equity Securities \| Quoted Prices in Active Markets (Level I) \| International
Employee post-retirement benefits
Fair value of plan assets	31	25
Equity Securities \| Significant Other Observable Inputs (Level II) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	113	95
Equity Securities \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	38	55
Equity Securities \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	263	231
Equity Securities \| Significant Other Observable Inputs (Level II) \| Global
Employee post-retirement benefits
Fair value of plan assets	13
Federal Bonds \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 314	$ 303
Percentage of Total Portfolio	17.00%	18.00%
Federal Bonds \| Significant Other Observable Inputs (Level II) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 314	$ 303
Provincial Bonds \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 161	$ 158
Percentage of Total Portfolio	9.00%	9.00%
Provincial Bonds \| Significant Other Observable Inputs (Level II) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 161	$ 158
Municipal Bonds \| Canadian
Employee post-retirement benefits
Fair value of plan assets	5	4
Municipal Bonds \| Significant Other Observable Inputs (Level II) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	5	4
State Bonds \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 33	$ 29
Percentage of Total Portfolio	2.00%	2.00%
State Bonds \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 33	$ 29
Corporate Bonds / Debt Securities \| Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 65	$ 47
Percentage of Total Portfolio	4.00%	3.00%
Corporate Bonds / Debt Securities \| U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 45	$ 29
Percentage of Total Portfolio	2.00%	2.00%
Corporate Bonds / Debt Securities \| International
Employee post-retirement benefits
Fair value of plan assets	$ 9	$ 9
Percentage of Total Portfolio		1.00%
Corporate Bonds / Debt Securities \| Significant Other Observable Inputs (Level II) \| Canadian
Employee post-retirement benefits
Fair value of plan assets	65	$ 47
Corporate Bonds / Debt Securities \| Significant Other Observable Inputs (Level II) \| U.S.
Employee post-retirement benefits
Fair value of plan assets	45	29
Corporate Bonds / Debt Securities \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	9	9
Mortgage Backed \| International
Employee post-retirement benefits
Fair value of plan assets	$ 22	$ 30
Percentage of Total Portfolio	1.00%	2.00%
Mortgage Backed \| Significant Other Observable Inputs (Level II) \| International
Employee post-retirement benefits
Fair value of plan assets	$ 22	$ 30
Other Investments: Private Equity Funds
Employee post-retirement benefits
Fair value of plan assets	$ 19	$ 20
Percentage of Total Portfolio	1.00%	1.00%
Other Investments: Private Equity Funds \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	$ 19	$ 20	$ 21

EMPLOYEE POST-RETIREMENT BENEFITS (Details 4) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Net change in the Level III fair value category
Plan assets at fair value - beginning of year	$ 1,685
Plan assets at fair value - end of year	1,857	$ 1,685
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value - beginning of year	20
Plan assets at fair value - end of year	19	20
Other Investments: Private Equity Funds
Net change in the Level III fair value category
Plan assets at fair value - beginning of year	20
Plan assets at fair value - end of year	19	20
Other Investments: Private Equity Funds \| Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value - beginning of year	20	21
Realized and unrealized losses	(1)	(2)
Purchases and sales		1
Plan assets at fair value - end of year	$ 19	$ 20

The difference between fair value of plan assets at the end of the period and the fair value at the beginning of the period, adjusted for contributions and payments of benefits during the period, and after adjusting for taxes and other expenses, as applicable.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Actual Return on Plan Assets (Component of Net Periodic Postretirement Benefit Cost)
-URI http://asc.fasb.org/extlink&oid=6504192

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (b)(1)
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Actual Return on Plan Assets (Component of Net Periodic Pension Cost)
-URI http://asc.fasb.org/extlink&oid=6504226

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph d(iv)(b)(i)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Assets, usually stocks, bonds, and other investments, that have been segregated and restricted (usually in a trust) to provide benefits, at their fair value as of the measurement date. Plan assets include amounts contributed by the employer (and by employees for a contributory plan) and amounts earned from investing the contributions, less benefits paid. If a plan has liabilities other than for benefits, those non-benefit obligations may be considered as reductions of plan assets.